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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2010
OR
     
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Transition Period from            to
         
Commission   Registrant, State of Incorporation,   I.R.S. Employer
File Number   Address and Telephone Number   Identification No.
1-3526
  The Southern Company   58-0690070
 
  (A Delaware Corporation)    
 
  30 Ivan Allen Jr. Boulevard, N.W.    
 
  Atlanta, Georgia 30308    
 
  (404) 506-5000    
 
       
1-3164
  Alabama Power Company   63-0004250
 
  (An Alabama Corporation)    
 
  600 North 18th Street    
 
  Birmingham, Alabama 35291    
 
  (205) 257-1000    
 
       
1-6468
  Georgia Power Company   58-0257110
 
  (A Georgia Corporation)    
 
  241 Ralph McGill Boulevard, N.E.    
 
  Atlanta, Georgia 30308    
 
  (404) 506-6526    
 
       
001-31737
  Gulf Power Company   59-0276810
 
  (A Florida Corporation)    
 
  One Energy Place    
 
  Pensacola, Florida 32520    
 
  (850) 444-6111    
 
       
001-11229
  Mississippi Power Company   64-0205820
 
  (A Mississippi Corporation)    
 
  2992 West Beach    
 
  Gulfport, Mississippi 39501    
 
  (228) 864-1211    
 
       
333-98553
  Southern Power Company   58-2598670
 
  (A Delaware Corporation)    
 
  30 Ivan Allen Jr. Boulevard, N.W.    
 
  Atlanta, Georgia 30308    
 
  (404) 506-5000    
 
 

 


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Securities registered pursuant to Section 12(b) of the Act:1
Each of the following classes or series of securities registered pursuant to Section 12(b) of the Act is listed on the New York Stock Exchange.
         
Title of each class
      Registrant
Common Stock, $5 par value
      The Southern Company
 
         
Class A preferred, cumulative, $25 stated capital   Alabama Power Company
5.20% Series
    5.83% Series    
5.30% Series
       
 
       
Senior Notes
       
5 7/8% Series GG
  5.875% Series II    
5.875% Series 2007B
  6.375% Series JJ    
 
         
Class A Preferred Stock, non-cumulative,
      Georgia Power Company
Par value $25 per share
       
6 1/8% Series
       
 
       
Senior Notes
       
6.375% Series 2007D
       
8.20% Series 2008C
       
 
       
Long-term debt payable to affiliated trusts,
       
$25 liquidation amount
       
5 7/8% Trust Preferred Securities2
       
 
         
Senior Notes
      Gulf Power Company
5.25% Series H
       
 
         
Senior Notes
      Mississippi Power Company
5 5/8% Series E
       
 
       
Depositary preferred shares, each representing one-fourth
of a share of preferred stock, cumulative, $100 par value
       
5.25% Series
       
 
 
1   As of December 31, 2010.
 
2   Issued by Georgia Power Capital Trust VII and guaranteed by Georgia Power Company.

 


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Securities registered pursuant to Section 12(g) of the Act:3
             
Title of each class
          Registrant
Preferred stock, cumulative, $100 par value       Alabama Power Company
4.20% Series
  4.60% Series   4.72% Series    
4.52% Series
  4.64% Series   4.92% Series    
 
             
Preferred stock, cumulative, $100 par value       Mississippi Power Company
4.40% Series
  4.60% Series        
4.72% Series
           
 
 
 
3   As of December 31, 2010.

 


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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
         
Registrant   Yes   No
The Southern Company
  ü    
Alabama Power Company
  ü    
Georgia Power Company
  ü    
Gulf Power Company
      ü
Mississippi Power Company
      ü
Southern Power Company
      ü
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ (Response applicable to all registrants.)
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes þ No o (Response applicable only to The Southern Company at this time.)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
                 
    Large           Smaller
    Accelerated   Accelerated   Non-accelerated   Reporting
Registrant   Filer   Filer   Filer   Company
The Southern Company
  ü            
Alabama Power Company
          ü    
Georgia Power Company
          ü    
Gulf Power Company
          ü    
Mississippi Power Company
          ü    
Southern Power Company
          ü    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ (Response applicable to all registrants.)

 


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Aggregate market value of The Southern Company’s common stock held by non-affiliates of The Southern Company at June 30, 2010: $27.6 billion. All of the common stock of the other registrants is held by The Southern Company. A description of each registrant’s common stock follows:
             
    Description of   Shares Outstanding
Registrant   Common Stock   at January 31, 2011
The Southern Company
  Par Value $5 Per Share     845,614,704  
Alabama Power Company
  Par Value $40 Per Share     30,537,500  
Georgia Power Company
  Without Par Value     9,261,500  
Gulf Power Company
  Without Par Value     4,142,717  
Mississippi Power Company
  Without Par Value     1,121,000  
Southern Power Company
  Par Value $0.01 Per Share     1,000  
Documents incorporated by reference: specified portions of The Southern Company’s Definitive Proxy Statement on Schedule 14A relating to the 2011 Annual Meeting of Stockholders are incorporated by reference into PART III. In addition, specified portions of the Definitive Information Statements on Schedule 14C of Alabama Power Company, Georgia Power Company, and Mississippi Power Company relating to each of their respective 2011 Annual Meetings of Shareholders are incorporated by reference into PART III.
Southern Power Company meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format specified in General Instructions I(2)(b), (c), and (d) of Form 10-K.
This combined Form 10-K is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.
 

 


 

Table of Contents
             
           Page   
 
  PART I    
 
       
  Business   I-1
 
  The Southern Company System   I-2
 
  Construction Programs   I-4
 
  Financing Programs   I-4
 
  Fuel Supply   I-5
 
  Territory Served by the Traditional Operating Companies and Southern Power   I-5
 
  Competition   I-7
 
  Seasonality   I-8
 
  Regulation   I-9
 
  Rate Matters   I-11
 
  Employee Relations   I-16
  Risk Factors   I-17
  Unresolved Staff Comments   I-29
  Properties   I-30
  Legal Proceedings   I-34
 
  Executive Officers of Southern Company   I-35
 
  Executive Officers of Alabama Power   I-37
 
  Executive Officers of Georgia Power   I-38
 
  Executive Officers of Mississippi Power   I-40
 
       
 
  PART II    
 
       
  Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   II-1
  Selected Financial Data   II-2
  Management’s Discussion and Analysis of Financial Condition and Results of Operations   II-2
  Quantitative and Qualitative Disclosures about Market Risk   II-3
  Financial Statements and Supplementary Data   II-4
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   II-5
  Controls and Procedures   II-6
  Other Information   II-7
 
       
 
  PART III    
 
       
  Directors, Executive Officers and Corporate Governance   III-1
  Executive Compensation   III-4
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   III-45
  Certain Relationships and Related Transactions, and Director Independence   III-46
  Principal Accountant Fees and Services   III-47
 
       
 
  PART IV    
 
       
  Exhibits and Financial Statement Schedules   IV-1
 
  Signatures   IV-2


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DEFINITIONS
When used in Items 1 through 5 and Items 9A through 15, the following terms will have the meanings indicated.
     
Term   Meaning
2010 ARP
  Alternative Rate Plan approved by the Georgia PSC for Georgia Power for the years 2011 through 2013
AFUDC
  Allowance for Funds Used During Construction
Alabama Power
  Alabama Power Company
AMEA
  Alabama Municipal Electric Authority
Clean Air Act
  Clean Air Act Amendments of 1990
Code
  Internal Revenue Code of 1986, as amended
CPCN
  Certificate of Public Convenience and Necessity
Dalton
  Dalton Utilities
DOE
  United States Department of Energy
Duke Energy
  Duke Energy Corporation
ECCR
  Georgia Power Environmental Compliance Cost Recovery
Energy Act of 1992
  Energy Policy Act of 1992
Energy Act of 2005
  Energy Policy Act of 2005
EPA
  United States Environmental Protection Agency
FERC
  Federal Energy Regulatory Commission
FMPA
  Florida Municipal Power Agency
FP&L
  Florida Power & Light Company
Georgia Power
  Georgia Power Company
Gulf Power
  Gulf Power Company
Hampton
  City of Hampton, Georgia
IBEW
  International Brotherhood of Electrical Workers
IGCC
  Integrated Coal Gasification Combined Cycle
IIC
  Intercompany Interchange Contract
IPP
  Independent Power Producer
IRP
  Integrated Resource Plan
IRS
  Internal Revenue Service
Kemper IGCC
  IGCC facility under construction in Kemper County, Mississippi
KUA
  Kissimmee Utility Authority
MEAG Power
  Municipal Electric Authority of Georgia
Mirant
  Mirant Corporation
Mississippi Power
  Mississippi Power Company
Moody’s
  Moody’s Investors Service
NRC
  Nuclear Regulatory Commission
OPC
  Oglethorpe Power Corporation
OUC
  Orlando Utilities Commission
power pool
  The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations
PowerSouth
  PowerSouth Energy Cooperative (formerly, Alabama Electric Cooperative, Inc.)
PPA
  Power Purchase Agreement
Progress Energy Carolinas
  Carolina Power & Light Company, d/b/a Progress Energy Carolinas, Inc.

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DEFINITIONS
(continued)
     
Term   Meaning
Progress Energy Florida
  Florida Power Corporation, d/b/a Progress Energy Florida, Inc.
PSC
  Public Service Commission
registrants
  The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company
RFP
  Request for Proposal
RUS
  Rural Utilities Service (formerly Rural Electrification Administration)
S&P
  Standard & Poor’s, a division of The McGraw-Hill Companies
SCS
  Southern Company Services, Inc. (the system service company)
SEC
  Securities and Exchange Commission
SEGCO
  Southern Electric Generating Company
SEPA
  Southeastern Power Administration
SERC
  Southeastern Electric Reliability Council
SMEPA
  South Mississippi Electric Power Association
Southern Company
  The Southern Company
Southern Company system
  Southern Company, the traditional operating companies, Southern Power, SEGCO, Southern Nuclear, SCS, SouthernLINC Wireless, and other subsidiaries
Southern Holdings
  Southern Company Holdings, Inc.
SouthernLINC Wireless
  Southern Communications Services, Inc.
Southern Nuclear
  Southern Nuclear Operating Company, Inc.
Southern Power
  Southern Power Company
Southern Renewable Energy
  Southern Renewable Energy, Inc.
Stone & Webster
  Stone & Webster, Inc.
traditional operating companies
  Alabama Power Company, Georgia Power Company, Gulf Power Company, and Mississippi Power Company
TVA
  Tennessee Valley Authority
Westinghouse
  Westinghouse Electric Company LLC

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CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the wholesale business, retail sales, customer growth, economic recovery, fuel cost recovery and other rate actions, environmental regulations and expenditures, future earnings, dividend payout ratios, access to sources of capital, projections for the qualified pension, postretirement benefit, and nuclear decommissioning trust fund contributions, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impact of the American Recovery and Reinvestment Act of 2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 2010, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
  the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
  current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS audits;
  the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;
  variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures;
  available sources and costs of fuels;
  effects of inflation;
  ability to control costs and avoid cost overruns during the development and construction of facilities;
  investment performance of Southern Company’s employee benefit plans and nuclear decommissioning trust funds;
  advances in technology;
  state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
  regulatory approvals and actions related to the Plant Vogtle expansion, including Georgia PSC and NRC approvals and potential DOE loan guarantees;
  regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC approvals and potential DOE loan guarantees;
  the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
  internal restructuring or other restructuring options that may be pursued;
  potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
  the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
  the ability to obtain new short- and long-term contracts with wholesale customers;
  the direct or indirect effect on Southern Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
  interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company’s and its subsidiaries’ credit ratings;
  the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices;
  catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as influenzas, or other similar occurrences;
  the direct or indirect effects on Southern Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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  the effect of accounting pronouncements issued periodically by standard setting bodies; and
  other factors discussed elsewhere herein and in other reports filed by the registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.


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PART I
Item 1. BUSINESS
Southern Company was incorporated under the laws of Delaware on November 9, 1945. Southern Company is domesticated under the laws of Georgia and is qualified to do business as a foreign corporation under the laws of Alabama. Southern Company owns all of the outstanding common stock of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power, each of which is an operating public utility company. The traditional operating companies supply electric service in the states of Alabama, Georgia, Florida, and Mississippi. More particular information relating to each of the traditional operating companies is as follows:
    Alabama Power is a corporation organized under the laws of the State of Alabama on November 10, 1927, by the consolidation of a predecessor Alabama Power Company, Gulf Electric Company, and Houston Power Company. The predecessor Alabama Power Company had been in continuous existence since its incorporation in 1906.
    Georgia Power was incorporated under the laws of the State of Georgia on June 26, 1930 and was admitted to do business in Alabama on September 15, 1948.
    Gulf Power is a Florida corporation that has had a continuous existence since it was originally organized under the laws of the State of Maine on November 2, 1925. Gulf Power was admitted to do business in Florida on January 15, 1926, in Mississippi on October 25, 1976, and in Georgia on November 20, 1984. Gulf Power became a Florida corporation after being domesticated under the laws of the State of Florida on November 2, 2005.
    Mississippi Power was incorporated under the laws of the State of Mississippi on July 12, 1972, was admitted to do business in Alabama on November 28, 1972, and effective December 21, 1972, by the merger into it of the predecessor Mississippi Power Company, succeeded to the business and properties of the latter company. The predecessor Mississippi Power Company was incorporated under the laws of the State of Maine on November 24, 1924 and was admitted to do business in Mississippi on December 23, 1924 and in Alabama on December 7, 1962.
In addition, Southern Company owns all of the common stock of Southern Power, which is also an operating public utility company. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. Southern Power is a corporation organized under the laws of Delaware on January 8, 2001 and was admitted to do business in the States of Alabama, Florida, and Georgia on January 10, 2001, in the State of Mississippi on January 30, 2001, and in the State of North Carolina on February 19, 2007.
Southern Company also owns all of the outstanding common stock or membership interests of SouthernLINC Wireless, Southern Nuclear, SCS, Southern Holdings, Southern Renewable Energy, and other direct and indirect subsidiaries. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and markets these services to the public and also provides wholesale fiber optic solutions to telecommunication providers in the Southeast. Southern Nuclear operates and provides services to Alabama Power’s and Georgia Power’s nuclear plants and is currently developing new nuclear generation at Plant Vogtle. SCS is the system service company providing, at cost, specialized services to Southern Company and its subsidiary companies. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in leveraged leases. Southern Renewable Energy was formed in January 2010 to construct, acquire, own, and manage renewable generation assets.
Alabama Power and Georgia Power each own 50% of the outstanding common stock of SEGCO. SEGCO is an operating public utility company that owns electric generating units with an aggregate capacity of 1,019,680 kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama. Alabama Power and Georgia Power are each entitled to one-half of SEGCO’s capacity and energy. Alabama Power acts as SEGCO’s agent in the operation of SEGCO’s units and furnishes coal to SEGCO as fuel for its units. SEGCO also owns one 230,000 volt transmission line extending from Plant Gaston to the Georgia state line at which point connection is made with the Georgia Power transmission line system.

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Southern Company’s segment information is included in Note 12 to the financial statements of Southern Company in Item 8 herein.
The registrants’ Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports are made available on Southern Company’s website, free of charge, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Southern Company’s internet address is www.southerncompany.com.
The Southern Company System
Traditional Operating Companies
The traditional operating companies own generation, transmission, and distribution facilities. See PROPERTIES in Item 2 herein for additional information on the traditional operating companies’ generating facilities. Each company’s transmission facilities are connected to the respective company’s own generating plants and other sources of power (including certain generating plants owned by Southern Power) and are interconnected with the transmission facilities of the other traditional operating companies and SEGCO. For information on the State of Georgia’s integrated transmission system, see “Territory Served by the Traditional Operating Companies and Southern Power” herein.
Agreements in effect with principal neighboring utility systems provide for capacity and energy transactions that may be entered into from time to time for reasons related to reliability or economics. Additionally, the traditional operating companies have entered into voluntary reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power Coordinating Group, and TVA and with Progress Energy Carolinas, Duke Energy, South Carolina Electric & Gas Company, and Virginia Electric and Power Company, each of which provides for the establishment and periodic review of principles and procedures for planning and operation of generation and transmission facilities, maintenance schedules, load retention programs, emergency operations, and other matters affecting the reliability of bulk power supply. The traditional operating companies have joined with other utilities in the Southeast (including some of those referred to above) to form the SERC to augment further the reliability and adequacy of bulk power supply. Through the SERC, the traditional operating companies are represented on the National Electric Reliability Council.
The utility assets of the traditional operating companies and certain utility assets of Southern Power are operated as a single integrated electric system, or power pool, pursuant to the IIC. Activities under the IIC are administered by SCS, which acts as agent for the traditional operating companies and Southern Power. The fundamental purpose of the power pool is to provide for the coordinated operation of the electric facilities in an effort to achieve the maximum possible economies consistent with the highest practicable reliability of service. Subject to service requirements and other operating limitations, system resources are committed and controlled through the application of centralized economic dispatch. Under the IIC, each traditional operating company and Southern Power retains its lowest cost energy resources for the benefit of its own customers and delivers any excess energy to the power pool for use in serving customers of other traditional operating companies or Southern Power or for sale by the power pool to third parties. The IIC provides for the recovery of specified costs associated with the affiliated operations thereunder, as well as the proportionate sharing of costs and revenues resulting from power pool transactions with third parties.
Southern Company, each traditional operating company, Southern Power, Southern Nuclear, SEGCO, and other subsidiaries have contracted with SCS to furnish, at direct or allocated cost and upon request, the following services: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations and power pool transactions. Southern Power and SouthernLINC Wireless have also secured from the traditional operating companies certain services which are furnished at cost and, in the case of Southern Power, which are subject to FERC regulations, in compliance with such regulations.

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Alabama Power and Georgia Power each have a contract with Southern Nuclear to operate Plant Farley and Plants Hatch and Vogtle, respectively. In addition, Georgia Power has a contract with Southern Nuclear to develop, license, construct, and operate additional generating units at Plant Vogtle. See “Regulation – Nuclear Regulation” herein for additional information.
Southern Power
Southern Power is an electric wholesale generation subsidiary with market-based rate authority from the FERC. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based prices in the wholesale market. Southern Power’s business activities are not subject to traditional state regulation like the traditional operating companies but are subject to regulation by the FERC. Southern Power has attempted to insulate itself from significant fuel supply, fuel transportation, and electric transmission risks by making such risks the responsibility of the counterparties to its PPAs. However, Southern Power’s future earnings will depend on the parameters of the wholesale market, federal regulation, and the efficient operation of its wholesale generating assets. For additional information on Southern Power’s business activities, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Business Activities” of Southern Power in Item 7 herein.
In 2008, Southern Power completed construction on Plant Franklin Unit 3 which added 659 megawatts to the Southern Company system generating capacity. Southern Power is constructing a 720-megawatt electric generating plant in Cleveland County, North Carolina. This new plant is expected to go into commercial operation in 2012. The total estimated construction cost is expected to be between $350 million and $400 million.
In October 2009, Southern Power acquired all of the outstanding membership interests of Nacogdoches Power LLC from American Renewables LLC, the original developer of a biomass project in Sacul, Texas. Southern Power continues to construct the Nacogdoches biomass generating plant with an estimated capacity of 100 megawatts. The generating plant will be fueled from wood waste and is expected to begin commercial operation in 2012. The total estimated cost of the project is expected to be between $475 million and $500 million.
In December 2009, Southern Power acquired all of the outstanding membership interests of West Georgia Generating Company, LLC (West Georgia) from Broadway Gen Funding, LLC, an affiliate of LS Power. West Georgia was merged into Southern Power as of the acquisition date and Southern Power now owns a dual-fueled generating plant near Thomaston, Georgia with nameplate capacity of approximately 669 megawatts. The plant consists of four combustion turbine natural gas generating units with oil back-up.
As of December 31, 2010, Southern Power had 7,880 megawatts of nameplate capacity in commercial operation.
Other Businesses
Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in leveraged leases.
SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and markets its services to non-affiliates within the Southeast. SouthernLINC Wireless delivers multiple wireless communication options including push to talk, cellular service, text messaging, wireless internet access, and wireless data. Its system covers approximately 127,000 square miles in the Southeast. SouthernLINC Wireless also provides wholesale fiber optic solutions to telecommunication providers in the Southeast under the name Southern Telecom.
On January 25, 2010, Southern Renewable Energy was formed to construct, acquire, own, and manage renewable generation assets. On March 12, 2010, Southern Renewable Energy and Turner Renewable Energy acquired from First Solar, Inc. the Cimarron project, a 30-megawatt solar photovoltaic plant near Cimarron, New Mexico. On November 25, 2010, the Cimarron plant began commercial operation.
These efforts to invest in and develop new business opportunities offer potential returns exceeding those of rate-regulated operations. However, these activities also involve a higher degree of risk.

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Construction Programs
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. For estimated construction and environmental expenditures for the periods 2011 through 2013, see Note 7 to the financial statements of Southern Company and each traditional operating company under “Construction Program” and Note 7 to the financial statements of Southern Power under “Expansion Program” in Item 8 herein. Base level estimated construction costs in 2011 are expected to be apportioned approximately as follows: (in millions)
                                                 
    Southern                    
    Company   Alabama   Georgia   Gulf   Mississippi   Southern
    System *   Power   Power   Power   Power   Power
     
New Generation
  $ 2,171     $     $ 934     $     $ 665     $ 572  
Environmental **
    341       47       73       176       45        
Transmission & Distribution Growth
    530       123       349       39       20        
Maintenance (Generation, Transmission & Distribution)
    1,270       532       489       154       79        
Nuclear fuel
    299       129       170                    
General plant
    278       86       95       12       9       27  
     
Total ***
  $ 4,889     $ 917     $ 2,110     $ 381     $ 818     $ 599  
     
 
*   These amounts include the traditional operating companies and Southern Power (as detailed in the table above) as well as the amounts for the other subsidiaries. See “Other Businesses” herein for additional information.
 
**   These amounts reflect estimated capital expenditures in 2011 to comply with existing statutes and regulations. In addition, each of Southern Company and the traditional operating companies has estimated of a range of potential incremental investments to comply with proposed environmental regulations. These additional estimated amounts for 2011 are: from $74 million to $289 million for the Southern Company system; up to $48 million for Alabama Power; from $69 million to $289 million for Georgia Power; and up to $17 million for Gulf Power. Mississippi Power and Southern Power have no anticipated incremental investments to comply with anticipated new environmental regulation in 2011.
 
***   The estimated 2011 total for Southern Power includes cash payments for long-term service agreements.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirement and replacement decisions, to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
See “Regulation – Environmental Statutes and Regulations” herein for additional information with respect to certain existing and proposed environmental requirements and PROPERTIES – “Jointly-Owned Facilities” in Item 2 herein for additional information concerning Alabama Power’s, Georgia Power’s, and Southern Power’s joint ownership of certain generating units and related facilities with certain non-affiliated utilities.
Financing Programs
See each of the registrant’s MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY in Item 7 herein and Note 6 to the financial statements of each registrant in Item 8 herein for information concerning financing programs.

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Fuel Supply
The traditional operating companies’ and SEGCO’s supply of electricity is derived mainly from coal. Southern Power’s supply of electricity is primarily fueled by natural gas. See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – “Fuel and Purchased Power Expenses” of Southern Company and each traditional operating company in Item 7 herein for information regarding the electricity generated and the average cost of fuel in cents per net kilowatt-hour generated for the years 2008 through 2010.
The traditional operating companies have agreements in place from which they expect to receive approximately 97.5% of their coal burn requirements in 2011. These agreements have terms ranging between one and eight years. In 2010, the weighted average sulfur content of all coal burned by the traditional operating companies was 0.78% sulfur. This sulfur level, along with banked and purchased sulfur dioxide allowances, allowed the traditional operating companies to remain within limits set by Phase I of the Clean Air Interstate Rule under the Clean Air Act. In 2010, the Southern Company system purchased approximately 35,000 tons of sulfur dioxide allowances, 6,650 tons of annual nitrogen oxide emissions allowances, and 2,100 tons of seasonal nitrogen oxide emission allowances to be used in current and future periods. As additional environmental regulations are proposed that impact the utilization of coal, the traditional operating companies’ fuel mix will be monitored to ensure that the traditional operating companies remain in compliance with applicable laws and regulations. Additionally, Southern Company and the traditional operating companies will continue to evaluate the need to purchase additional emissions allowances, the timing of capital expenditures for emissions control equipment, and potential unit retirements and replacements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Southern Company and each traditional operating company in Item 7 herein for information on the Clean Air Act, water quality, coal combustion byproducts, and global climate issues.
SCS, acting on behalf of the traditional operating companies and Southern Power, has agreements in place for the natural gas burn requirements of the Southern Company system. For 2011, SCS has contracted for 255 billion cubic feet of natural gas supply under agreements with remaining terms up to 10 years. In addition to gas supply, SCS has contracts in place for both firm gas transportation and storage. Management believes that these contracts provide sufficient natural gas supplies, transportation, and storage to ensure normal operations of the Southern Company system’s natural gas generating units.
Changes in fuel prices to the traditional operating companies are generally reflected in fuel adjustment clauses contained in rate schedules. See “Rate Matters – Rate Structure and Cost Recovery Plans” herein for additional information. Southern Power’s PPAs generally provide that the counterparty is responsible for substantially all of the cost of fuel.
Alabama Power and Georgia Power have numerous contracts covering a portion of their nuclear fuel needs for uranium, conversion services, enrichment services, and fuel fabrication. These contracts have varying expiration dates and most of them are for less than 10 years. Management believes that sufficient capacity for nuclear fuel supplies and processing exists to preclude the impairment of normal operations of the Southern Company system’s nuclear generating units.
Alabama Power and Georgia Power have contracts with the United States, acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in 1998, as required by the contracts, and Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of contract. See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under “Nuclear Fuel Disposal Costs” in Item 8 herein for additional information.
Territory Served by the Traditional Operating Companies and Southern Power
The territory in which the traditional operating companies provide electric service comprises most of the states of Alabama and Georgia together with the northwestern portion of Florida and southeastern Mississippi. In this territory there are non-affiliated electric distribution systems which obtain some or all of their power requirements either directly or indirectly from the traditional operating companies. The territory has an area of approximately 120,000 square miles and an estimated population of approximately 13 million. Southern Power sells electricity at market-based prices in the wholesale market to investor-owned utilities, IPPs, municipalities, and electric cooperatives.

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Alabama Power is engaged, within the State of Alabama, in the generation and purchase of electricity and the transmission, distribution, and sale of such electricity at retail in over 650 communities (including Anniston, Birmingham, Gadsden, Mobile, Montgomery, and Tuscaloosa), as well as in rural areas, and at wholesale to 15 municipally-owned electric distribution systems, 11 of which are served indirectly through sales to AMEA, and two rural distributing cooperative associations. Alabama Power owns coal reserves near its Plant Gorgas and uses the output of coal from the reserves in its generating plants. Alabama Power also sells, and cooperates with dealers in promoting the sale of, electric appliances.
Georgia Power is engaged in the generation and purchase of electricity and the transmission, distribution, and sale of such electricity within the State of Georgia at retail in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon, Rome, and Savannah), as well as in rural areas, and at wholesale currently to OPC, MEAG Power, Dalton, Hampton, and various electric membership corporations.
Gulf Power is engaged, within the northwestern portion of Florida, in the generation and purchase of electricity and the transmission, distribution, and sale of such electricity at retail in 71 communities (including Pensacola, Panama City, and Fort Walton Beach), as well as in rural areas, and at wholesale to a non-affiliated utility and a municipality.
Mississippi Power is engaged in the generation and purchase of electricity and the transmission, distribution, and sale of such electricity within 23 counties in southeastern Mississippi, at retail in 123 communities (including Biloxi, Gulfport, Hattiesburg, Laurel, Meridian, and Pascagoula), as well as in rural areas, and at wholesale to one municipality, six rural electric distribution cooperative associations, and one generating and transmitting cooperative.
For information relating to kilowatt-hour sales by customer classification for the traditional operating companies, see MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS of each traditional operating company in Item 7 herein. Also, for information relating to the sources of revenues for Southern Company, each traditional operating company, and Southern Power, reference is made to Item 7 herein.
The RUS has authority to make loans to cooperative associations or corporations to enable them to provide electric service to customers in rural sections of the country. There are 71 electric cooperative organizations operating in the territory in which the traditional operating companies provide electric service at retail or wholesale.
One of these organizations, PowerSouth, is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems, and other customers in south Alabama and northwest Florida. PowerSouth owns generating units with approximately 1,776 megawatts of nameplate capacity, including an undivided 8.16% ownership interest in Alabama Power’s Plant Miller Units 1 and 2. PowerSouth’s facilities were financed with RUS loans secured by long-term contracts requiring distributing cooperatives to take their requirements from PowerSouth to the extent such energy is available.
Alabama Power and Gulf Power have entered into separate agreements with PowerSouth involving interconnection between their respective systems. The delivery of capacity and energy from PowerSouth to certain distributing cooperatives in the service areas of Alabama Power and Gulf Power is governed by the Southern Company/PowerSouth Network Transmission Service Agreement. The rates for this service to PowerSouth are on file with the FERC. See PROPERTIES – “Jointly-Owned Facilities” in Item 2 herein for details of Alabama Power’s joint-ownership with PowerSouth of a portion of Plant Miller.
Four electric cooperative associations, financed by the RUS, operate within Gulf Power’s service area. These cooperatives purchase their full requirements from PowerSouth and SEPA (a federal power marketing agency). A non-affiliated utility also operates within Gulf Power’s service area and purchases its full requirements from Gulf Power.
Mississippi Power has an interchange agreement with SMEPA, a generating and transmitting cooperative, pursuant to which various services are provided, including the furnishing of protective capacity by Mississippi Power to

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SMEPA. On July 27, 2010, Mississippi Power and SMEPA entered into an asset purchase agreement whereby SMEPA will purchase an undivided 17.5% interest in the Kemper IGCC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. On December 2, 2010, Mississippi Power and SMEPA filed a joint petition with the Mississippi PSC requesting regulatory approval for SMEPA’s 17.5% ownership of the Kemper IGCC.
There are also 65 municipally-owned electric distribution systems operating in the territory in which the traditional operating companies provide electric service at retail or wholesale.
Forty-eight municipally-owned electric distribution systems and one county-owned system receive their requirements through MEAG Power, which was established by a Georgia state statute in 1975. MEAG Power serves these requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, power purchased from Georgia Power, and purchases from other resources. MEAG Power also has a pseudo scheduling and services agreement with Georgia Power. Dalton serves its requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and through purchases from Georgia Power and Southern Power through a service agreement. In addition, Georgia Power serves the full requirements of Hampton’s electric distribution system under a market-based contract. See PROPERTIES – “Jointly-Owned Facilities” in Item 2 herein for additional information.
Georgia Power has entered into substantially similar agreements with Georgia Transmission Corporation (formerly OPC’s transmission division), MEAG Power, and Dalton providing for the establishment of an integrated transmission system to carry the power and energy of all parties. The agreements require an investment by each party in the integrated transmission system in proportion to its respective share of the aggregate system load. See PROPERTIES – “Jointly-Owned Facilities” in Item 2 herein for additional information.
Southern Power has PPAs with some of the traditional operating companies and with other investor-owned utilities, IPPs, municipalities, and electric cooperatives. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” of Southern Power in Item 7 herein for additional information concerning Southern Power’s PPAs.
SCS, acting on behalf of the traditional operating companies, also has a contract with SEPA providing for the use of the traditional operating companies’ facilities at government expense to deliver to certain cooperatives and municipalities, entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain United States government hydroelectric projects.
Pursuant to the 1956 Utility Act, the Mississippi PSC issued “Grandfather Certificates” of public convenience and necessity to Mississippi Power and to six distribution rural cooperatives operating in southeastern Mississippi, then served in whole or in part by Mississippi Power, authorizing them to distribute electricity in certain specified geographically described areas of the state. The six cooperatives serve approximately 325,000 retail customers in a certificated area of approximately 10,300 square miles. In areas included in a “Grandfather Certificate,” the utility holding such certificate may, without further certification, extend its lines up to five miles; other extensions within that area by such utility, or by other utilities, may not be made except upon a showing of, and a grant of a certificate of, public convenience and necessity. Areas included in such a certificate which are subsequently annexed to municipalities may continue to be served by the holder of the certificate, irrespective of whether it has a franchise in the annexing municipality. On the other hand, the holder of the municipal franchise may not extend service into such newly annexed area without authorization by the Mississippi PSC.
Competition
The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the early primary agents of change was the Energy Act of 1992 which allowed IPPs to access a utility’s transmission network in order to sell electricity to other utilities.
The competition for retail energy sales among competing suppliers of energy is influenced by various factors,

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including price, availability, technological advancements, service, and reliability. These factors are, in turn, affected by, among other influences, regulatory, political, and environmental considerations, taxation, and supply.
The retail service rights of all electric suppliers in the State of Georgia are regulated by the Territorial Electric Service Act of 1973. Pursuant to the provisions of this Act, all areas within existing municipal limits were assigned to the primary electric supplier therein. Areas outside of such municipal limits were either to be assigned or to be declared open for customer choice of supplier by action of the Georgia PSC pursuant to standards set forth in this Act. Consistent with such standards, the Georgia PSC has assigned substantially all of the land area in the state to a supplier. Notwithstanding such assignments, this Act provides that any new customer locating outside of 1973 municipal limits and having a connected load of at least 900 kilowatts may exercise a one-time choice for the life of the premises to receive electric service from the supplier of its choice.
Generally, the traditional operating companies have experienced, and expect to continue to experience, competition in their respective retail service territories in varying degrees as the result of self-generation (as described below) by customers and other factors.
Southern Power competes with investor owned utilities, IPPs, and others for wholesale energy sales primarily in the Southeastern United States wholesale market. The needs of this market are driven by the demands of end users in the Southeast and the generation available. Southern Power’s success in wholesale energy sales is influenced by various factors including reliability and availability of Southern Power’s plants, availability of transmission to serve the demand, price, and Southern Power’s ability to contain costs.
Alabama Power currently has cogeneration contracts in effect with 10 industrial customers. Under the terms of these contracts, Alabama Power purchases excess generation of such companies. During 2010, Alabama Power purchased approximately 194 million kilowatt-hours from such companies at a cost of $8.2 million.
Georgia Power currently has contracts in effect with 11 small power producers whereby Georgia Power purchases their excess generation. During 2010, Georgia Power purchased 45 million kilowatt-hours from such companies at a cost of $1.6 million. Georgia Power has PPAs for electricity with two cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2010, Georgia Power purchased 178 million kilowatt-hours at a cost of $27.7 million from these facilities.
Also during 2010, Georgia Power purchased energy from eight customer-owned generating facilities. Seven of the eight customers provide only energy to Georgia Power. These seven customers make no capacity commitment and are not dispatched by Georgia Power. Georgia Power does have a contract with the remaining customer for eight megawatts of dispatchable capacity and energy. During 2010, Georgia Power purchased a total of 49 million kilowatt-hours from the eight customers at a cost of approximately $1.9 million.
Gulf Power currently has agreements in effect with various industrial, commercial, and qualifying facilities pursuant to which Gulf Power purchases “as available” energy from customer-owned generation. During 2010, Gulf Power purchased 111.7 million kilowatt-hours from such companies for approximately $6.3 million.
Mississippi Power currently has a cogeneration agreement in effect with one of its industrial customers. Under the terms of this contract, Mississippi Power purchases any excess generation. During 2010, Mississippi Power did not purchase any excess generation from this customer.
Seasonality
The demand for electric power generation is affected by seasonal differences in the weather. At the traditional operating companies and Southern Power, the demand for power peaks during the summer months, with market prices reflecting the demand of power and available generating resources at that time. Power demand peaks can also be recorded during the winter. As a result, the overall operating results of Southern Company, the traditional operating companies, and Southern Power in the future may fluctuate substantially on a seasonal basis. In addition, Southern Company, the traditional operating companies, and Southern Power have historically sold less power when weather conditions are milder.

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Regulation
State Commissions
The traditional operating companies are subject to the jurisdiction of their respective state PSCs. The PSCs have broad powers of supervision and regulation over public utilities operating in the respective states, including their rates, service regulations, sales of securities (except for the Mississippi PSC), and, in the cases of the Georgia PSC and the Mississippi PSC, in part, retail service territories. See “Territory Served by the Traditional Operating Companies and Southern Power” and “Rate Matters” herein for additional information.
Federal Power Act
The traditional operating companies, Southern Power and its generation subsidiaries, SEGCO, and Southern Renewable Energy’s generation subsidiary are all public utilities engaged in wholesale sales of energy in interstate commerce and therefore are subject to the rate, financial, and accounting jurisdiction of the FERC under the Federal Power Act. The FERC must approve certain financings and allows an “at cost standard” for services rendered by system service companies such as SCS. The FERC is also authorized to establish regional reliability organizations which are authorized to enforce reliability standards, to address impediments to the construction of transmission, and to prohibit manipulative energy trading practices.
Alabama Power and Georgia Power are also subject to the provisions of the Federal Power Act or the earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric developments. Among the hydroelectric projects subject to licensing by the FERC are 14 existing Alabama Power generating stations having an aggregate installed capacity of 1,662,400 kilowatts and 18 existing Georgia Power generating stations having an aggregate installed capacity of 1,087,296 kilowatts.
In July 2005, Alabama Power filed two applications with the FERC for new 50-year licenses for its seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and for the Lewis Smith and Bankhead developments on the Warrior River. The FERC licenses for all of these nine developments expired in July and August 2007. Since the FERC did not act on any of the new license applications prior to the expiration of the existing licenses, the FERC is required by law to issue annual licenses under the terms and conditions of the existing licenses, until action is taken on the new license applications. The FERC issued an annual license to the Coosa developments in August 2007, which was automatically renewed in 2008, 2009, and 2010. On March 31, 2010, the FERC issued a new 30-year license for the Lewis Smith and Bankhead developments on the Warrior River. The new license authorizes Alabama Power to continue operating these facilities in a manner consistent with past operations. On April 30, 2010, a stakeholders group filed a request for rehearing of the FERC order issuing the new license. On May 27, 2010, the FERC granted the rehearing request for the limited purpose of allowing the FERC additional time to consider the substantive issues in the request.
In 2006, Alabama Power initiated the process of developing an application to relicense the Martin hydroelectric project located on the Tallapoosa River. The current Martin license will expire in 2013 and the application for a new license is expected to be filed with the FERC in 2011. In 2010, Alabama Power initiated the process of developing an application to relicense the Holt hydroelectric project located on Warrior River. The current Holt license will expire in August 2015 and the application for a new license is expected to be filed prior to that time.
In 2007, Georgia Power began the relicensing process for Bartlett’s Ferry which is located on the Chattahoochee River near Columbus, Georgia. The current Bartlett’s Ferry license expires in 2014 and the application for a new license is expected to be submitted to the FERC in 2012.
The ultimate outcome of these matters cannot be determined at this time. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters” of Alabama Power in Item 7 herein for additional information.
Georgia Power and OPC also have a license, expiring in 2027, for the Rocky Mountain Plant, a pure pumped storage facility of 847,800 kilowatt capacity. See PROPERTIES – “Jointly-Owned Facilities” in Item 2 herein for additional information.

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Licenses for all projects, excluding those discussed above, expire in the period 2023-2034 in the case of Alabama Power’s projects and in the period 2020-2039 in the case of Georgia Power’s projects.
Upon or after the expiration of each license, the United States Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another, the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property.
Nuclear Regulation
Alabama Power, Georgia Power, and Southern Nuclear are subject to regulation by the NRC. The NRC is responsible for licensing and regulating nuclear facilities and materials and for conducting research in support of the licensing and regulatory process, as mandated by the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and the Nuclear Nonproliferation Act of 1978; and in accordance with the National Environmental Policy Act of 1969, as amended, and other applicable statutes. These responsibilities also include protecting public health and safety, protecting the environment, protecting and safeguarding nuclear materials and nuclear power plants in the interest of national security, and assuring conformity with antitrust laws.
In January 2002, the NRC extended the licenses of Georgia Power’s Plant Hatch Units 1 and 2 until 2034 and 2038, respectively. In May 2005, the NRC extended the licenses of Alabama Power’s Plant Farley Units 1 and 2 until 2037 and 2041, respectively. In June 2009, the NRC extended the licenses of Plant Vogtle Units 1 and 2 to 2047 and 2049, respectively.
In August 2009, the NRC issued an Early Site Permit and Limited Work Authorization to Southern Nuclear, on behalf of Georgia Power, OPC, MEAG Power, and City of Dalton (collectively, Owners), related to two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4). In March 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license (COL) for Plant Vogtle Units 3 and 4, which, if licensed by the NRC, are scheduled to be placed in service in 2016 and 2017, respectively. Georgia Power currently expects to receive the Vogtle 3 and 4 COLs from the NRC in late 2011 based on the NRC’s February 16, 2011 release of its COL schedule framework. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Construction — Nuclear” of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power - Nuclear Construction” and Georgia Power under “Construction — Nuclear” in Item 8 herein for additional information.
See Notes 1 and 9 to the financial statements of Southern Company, Alabama Power, and Georgia Power in Item 8 herein for information on nuclear decommissioning costs and nuclear insurance.
Environmental Statutes and Regulations
Southern Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Compliance with these existing environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions or market-based rates for Southern Power. There is no assurance, however, that all such costs will be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for Southern Company, each traditional operating company, Southern Power, and SEGCO. In addition, existing environmental laws and regulations may be changed or new laws and regulations may be adopted or otherwise become applicable to Southern Company, the traditional operating companies, Southern Power, or SEGCO, including laws and regulations designed to address global climate change, air quality, water quality, management of waste materials and coal combustion byproducts, including coal ash, or other environmental, public health, and welfare concerns. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Southern Company and each of the traditional operating companies in

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Item 7 herein for additional information about the Clean Air Act and other environmental issues, including, but not limited to, the litigation brought by the EPA under the New Source Review provisions of the Clean Air Act, possible additional and/or revised regulations related to air and water quality, possible climate change legislation and regulation, and possible regulation of coal combustion byproducts. Also see MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Southern Power in Item 7 herein for information about environmental issues, possible climate change legislation and regulation and possible regulation of coal combustion byproducts.
Southern Company, the traditional operating companies, Southern Power, and SEGCO are unable to predict at this time what additional steps they may be required to take as a result of the implementation of existing or future requirements pertaining to climate change, air quality, water quality, and management of waste materials and coal combustion byproducts, including coal ash, but such steps could adversely affect system operations and result in substantial additional costs. For example, potential regulations relating to air quality could require the installation of additional environmental controls, potential regulations relating to water quality could require the installation of cooling towers at certain existing generating units, and potential regulations relating to coal combustion byproducts could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements.
Depending on the final outcome of the wide range of proposed environmental regulations currently under consideration by the EPA, the retirement and replacement of certain existing generating units may be more economically efficient than installing required controls necessary to remain in compliance. In addition, while the outcome of these matters cannot now be determined, potential additional environmental regulations could result in delays in obtaining appropriate licenses for generating facilities, increased construction and operating costs, or reduced generation, the nature and extent of which, while not determinable at this time, could be substantial. See “Construction Program” herein for additional information.
Rate Matters
Rate Structure and Cost Recovery Plans
The rates and service regulations of the traditional operating companies are uniform for each class of service throughout their respective service areas. Rates for residential electric service are generally of the block type based upon kilowatt-hours used and include minimum charges. Residential and other rates contain separate customer charges. Rates for commercial service are presently of the block type and, for large customers, the billing demand is generally used to determine capacity and minimum bill charges. These large customers’ rates are generally based upon usage by the customer and include rates with special features to encourage off-peak usage. Additionally, Alabama Power, Gulf Power, and Mississippi Power are generally allowed by their respective state PSCs to negotiate the terms and cost of service to large customers. Such terms and cost of service, however, are subject to final state PSC approval.
Fuel and net purchased energy costs are recovered through specific fuel cost recovery provisions at the traditional operating companies. These fuel cost recovery provisions are adjusted to reflect increases or decreases in such costs as needed. Gulf Power’s and Mississippi Power’s fuel cost recovery provisions are adjusted annually to reflect increases or decreases in such costs. Georgia Power is currently required to file its next fuel case by March 1, 2011, with a new rate to be effective June 1, 2011. Alabama Power’s fuel cost recovery rates are adjusted as required; a new rate is scheduled to be effective on April 1, 2011. Revenues are adjusted for differences between recoverable costs and amounts actually recovered in current rates.
Approved environmental compliance and storm damage costs are recovered at Alabama Power and Mississippi Power through cost recovery provisions approved by their respective state PSCs. Within limits approved by their respective PSCs, these rates are adjusted to reflect increases or decreases in such costs as required.
Georgia Power’s environmental compliance costs are recovered through its ECCR tariff. On December 21, 2010, the Georgia PSC voted to approve the 2010 ARP effective January 1, 2011 and continuing through December 31, 2013 under which the ECCR tariff has been continued. See Note 3 to the financial statements of Southern Company

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under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” and Georgia Power under “Retail Regulatory Matters — Rate Plans” in Item 8 herein for additional information.
See “Integrated Resource Planning” herein for a discussion of Georgia PSC certification of new demand-side or supply-side resources for Georgia Power. In addition, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Construction — Nuclear” of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and Georgia Power under “Construction — Nuclear” in Item 8 herein for a discussion of the Georgia Nuclear Energy Financing Act and the Georgia PSC certification of Plant Vogtle Units 3 and 4, which allow Georgia Power to recover financing costs for construction of the new nuclear units during the construction period beginning in 2011. On December 21, 2010, as a part of the 2010 ARP, the Georgia PSC approved Georgia Power’s Nuclear Construction Cost Recovery tariff effective January 1, 2011.
Alabama Power recovers the cost of certificated new plant and purchased power capacity through cost recovery provisions which are approved annually. Gulf Power files a rate clause request annually with the Florida PSC to recover costs associated with purchased power capacity, energy conservation, and environmental compliance. Revenues are adjusted for differences between recoverable costs and amounts actually recovered in current rates.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters” of Southern Company and each of the traditional operating companies in Item 7 herein and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters” and Note 3 to the financial statements of each of the traditional operating companies under “Retail Regulatory Matters” in Item 8 herein for a discussion of rate matters. Also, see Note 1 to the financial statements of Southern Company and each of the traditional operating companies in Item 8 herein for a discussion of recovery of fuel costs, storm damage costs, and environmental compliance costs through rates.
The traditional operating companies, Southern Power and its generation subsidiaries, and Southern Renewable Energy’s generation subsidiary are authorized by the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
Integrated Resource Planning
Each of the traditional operating companies continually evaluates its electric generating resources in order to ensure that it maintains a cost-effective and reliable mix of resources to meet the existing and future demand requirements of its customers. See “Environmental Statutes and Regulations” above for a discussion of existing and potential environmental regulations that may impact the future generating resource needs of the traditional operating companies.
Certain of the traditional operating companies periodically file IRPs with their respective state PSC. The following is a summary of the most recent IRP filings by certain of the traditional operating companies.
Georgia Power
Triennially, Georgia Power must file an IRP with the Georgia PSC that specifies how it intends to meet the future electrical needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC, under state law, must certify any new demand-side or supply-side resources for Georgia Power to get cost recovery. Once certified, the lesser of actual or certified construction costs and purchased power costs is recoverable through rates.
On January 29, 2010, Georgia Power filed its 2010 IRP with the Georgia PSC. The 2010 IRP projected that Georgia Power’s current supply-side and demand-side resources are sufficient to provide a cost-effective and reliable source of capacity and energy at least through 2014. The 2010 IRP identified a number of potential new or modified federal environmental statutes and regulations that could significantly impact Georgia Power’s existing coal-fired generating units. In addition, under the State of Georgia’s Multi-Pollutant Rule, Georgia Power is required to install specific emissions controls on certain coal-fired generating units by specific dates between December 31, 2008 and June 1, 2015. See “Environmental Statutes and Regulations” above.

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On July 6, 2010, the Georgia PSC approved Georgia Power’s 2010 IRP including the following provisions: (1) restarting an RFP to enable the potential replacement of coal units that may be retired beginning in approximately 2015; (2) expanding energy efficiency efforts; (3) implementing seven new demand-side management and energy efficiency programs; (4) collecting incentives totaling 10% of the net benefit of energy efficiency programs annually, with certain conditions, for the certified programs; (5) developing a one megawatt self-build portfolio of solar photovoltaic demonstration projects; (6) delaying capital spending on the conversion of Plant Mitchell Unit 3 from a coal-fired generating unit to a renewable biomass generating unit until the EPA issues applicable maximum achievable control technology (MACT) standards under the Clean Air Act; (7) considering conversion of additional coal units to biomass, if such conversions appear to be economic and feasible; and (8) continuing to suspend work on environmental controls for Units 6 and 7 at Plant Yates and Units 1 and 2 at Plant Branch until the EPA issues applicable MACT standards and regulations for coal combustion byproducts.
In addition, Georgia Power’s 2010 IRP reflected the construction of Plant McDonough Units 4, 5, and 6 (natural gas) and Plant Vogtle Units 3 and 4 (nuclear) as certified by the Georgia PSC in 2007 and 2009, respectively. In addition, the 2010 IRP also reflected the related retirement of Plant McDonough Units 1 and 2 (coal), which were decertified by the Georgia PSC in connection with construction of the new units. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Construction” of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and “Retail Regulatory Matters — Georgia Power — Other Construction” in Item 8 herein and Note 3 to the financial statements of Georgia Power under “Construction” in Item 8 herein for additional information
Georgia Power currently expects to file an update to its IRP in June 2011. Georgia Power is continuing to analyze the potential costs and benefits of installing environmental controls on its remaining coal-fired generating units in light of the potential new or modified environmental regulations. As contemplated in the 2010 IRP, Georgia Power may determine that retiring and replacing certain of these existing units with new generating resources or purchased power is more economically efficient than installing the required environmental controls. On April 20, 2010, Georgia Power issued an RFP for approximately 1,000 megawatts to assure a reliable and economic supply in the event replacement capacity is needed and is currently negotiating with counterparties that offered the most competitive proposals. Certification of any needed resources procured through the RFP would be expected by approximately February 2012.
Under the terms of Georgia Power’s 2010 ARP, any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets (resulting from new or revised environmental regulations) through 2013 that are approved by the Georgia PSC in connection with Georgia Power’s updated IRP will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. Such costs that may be deferred as a regulatory asset include any impairment losses that may result from a decision to retire certain units that are no longer cost effective in light of new or modified environmental regulations. In addition, in connection with Georgia Power’s 2010 ARP, the Georgia PSC also approved revised depreciation rates that will recover the remaining book value of certain of Georgia Power’s existing coal-fired units by December 31, 2014.
In addition, Georgia Power expects to file a request with the Georgia PSC in spring 2011 for the certification of 562 megawatts of certain wholesale capacity that will be returned to retail service on January 1, 2015 (312 megawatts) and April 1, 2016 (250 megawatts). On September 20, 2010, the Georgia PSC accepted Georgia Power’s offer to return this generating capacity to retail service.
The ultimate outcome of these matters cannot be determined at this time.
Gulf Power
Annually by April 1, Gulf Power must file a 10-year site plan with the Florida PSC containing Gulf Power’s estimate of its power-generating needs in the period and the general location of its proposed power plant sites. The 10-year site plans submitted by the state’s electric utilities are reviewed by the Florida PSC and subsequently classified as either “suitable” or “unsuitable.” The Florida PSC then reports its findings along with any suggested revisions to the Florida Department of Environmental Protection for its consideration at any subsequent electrical

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power plant site certification proceedings. Under Florida law, any 10-year site plans submitted by an electric utility are considered tentative information for planning purposes only and may be amended at any time at the discretion of the utility with written notification to the Florida PSC. At least every five years, the Florida PSC must conduct proceedings to establish numerical goals for all investor-owned electric utilities and certain municipal or cooperative electric utilities in the state to reduce the growth rates of weather-sensitive peak demand, to reduce and control the growth rates of electric consumption, and to increase the conservation of expensive resources, such as petroleum fuels. Overall residential kilowatts and kilowatt hours goals and overall commercial/industrial kilowatt and kilowatt hours goals for each utility are set by the Florida PSC for each year over a 10-year period. The goals are to be based on an estimate of the total cost effective kilowatts and kilowatt hours savings reasonably achievable through demand-side management in each utility’s service area over a 10-year period. Once goals have been set, each affected utility must develop and submit plans and programs to meet the overall goals within its service area to the Florida PSC for review and approval. Once approved, the utilities are required to submit periodic reports which the Florida PSC then uses to prepare its annual report to the Governor and Legislature of the goals that have been established and the progress towards meeting those goals.
Gulf Power’s most recent 10-year site plan was classified by the Florida PSC as “suitable” in December 2010. Gulf Power’s most recent 10-year site plan and environmental compliance plan identify potential environmental regulations relating to maximum achievable control technology for hazardous air pollutants and potential legislation or regulation that would impose mandatory restrictions on greenhouse gas emissions. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality,” “Environmental Matters — Environmental Statutes and Regulations — Coal Combustion Byproducts,” and “Environmental Matters — Global Climate Issues” of Gulf Power in Item 7 herein. The site plan and environmental compliance plan include preliminary retirement studies under a variety of potential scenarios for units at each of Gulf Power’s coal-fired generating plants. These studies indicate that, depending on the final requirements in these anticipated EPA regulations and any legislation or regulations relating to greenhouse gas emissions, as well as estimates of long-term fuel prices, Gulf Power may conclude that it is more economical to retire certain of its coal-fired generating units prior to 2020 and to replace such units with new or purchased capacity.
Also in December 2009, the Florida PSC adopted new numerical conservation goals for Gulf Power along with other electric utilities in the state. The Florida PSC adopted more aggressive goals due in part to the consideration of possible greenhouse gas emissions costs incurred in connection with possible climate change legislation and a change in the manner in which the Florida PSC considers the effect of so-called “free-riders” on the level of conservation reasonably achievable through utility programs. Gulf Power’s plans and programs to meet the new goals were submitted to the Florida PSC for review on March 30, 2010 and were approved on January 25, 2011. The costs of implementing Gulf Power’s conservation plans and programs are recovered through specific conservation recovery rates set annually by the Florida PSC.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
In December 2009, Mississippi Power filed its 2010 IRP with the Mississippi PSC. The filing was made in connection with the Mississippi PSC certification proceedings relating to a new electric generating plant located in Kemper County, Mississippi that would utilize an IGCC technology. In the 2010 IRP, Mississippi Power projected that it will have a need for new capacity in the 2013 to 2015 timeframe. The 2010 IRP indicated a need range of approximately 200 megawatts to 300 megawatts in 2014, which reflects growth in load and the anticipated retirement of older gas steam units Plant Eaton Units 1 through 3 and Plant Watson Units 1 through 3 in 2012 and 2013, respectively. In addition, due to potential retirements of existing coal units, the Mississippi PSC found a need in 2015 that ranges from 304 megawatts to 1,276 megawatts.
The range of needs for 2015 is based on potential environmental regulations relating to maximum achievable control technology for hazardous air pollutants, as well as potential legislation or regulations that would impose mandatory restrictions on greenhouse gas emissions. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” and “Environmental Matters — Global Climate Issues” of Mississippi Power in Item 7 herein. Depending on the final

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requirements in the anticipated EPA regulations and any legislation or regulation relating to greenhouse gas emissions, as well as estimates of long-term fuel prices, Mississippi Power may conclude that it is more economical to discontinue burning coal at certain coal-fired generating units than to install the required controls.
Mississippi Power’s 2010 IRP indicated that Mississippi Power plans to construct the Kemper IGCC to meet its identified needs, to add environmental controls at Plant Daniel Units 1 and 2, to defer environmental controls at Plant Watson Units 4 and 5, and to continue operation of the combined cycle Plant Daniel Units 3 and 4.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Base Load Construction Legislation
In the 2008 regular session of the Mississippi legislature, a bill was passed and signed by the Governor in May 2008 to enhance the Mississippi PSC’s authority to facilitate development and construction of base load generation in the State of Mississippi (Baseload Act). The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. The effect of this legislation on Southern Company and Mississippi Power cannot now be determined.
In January 2009, Mississippi Power filed for a CPCN with the Mississippi PSC to allow construction of the Kemper IGCC. On April 29, 2010, the Mississippi PSC issued an order finding that Mississippi Power’s application to acquire, construct, and operate the plant did not satisfy the requirement of public convenience and necessity in the form that the project and the related cost recovery were originally proposed by Mississippi Power, unless Mississippi Power accepted certain conditions on the issuance of the CPCN, including a cost cap of approximately $2.4 billion. On May 10, 2010, Mississippi Power filed a motion in response to the April 29, 2010 order of the Mississippi PSC relating to the Kemper IGCC, or in the alternative, for alteration or rehearing of such order.
On May 26, 2010, the Mississippi PSC issued an order revising its findings from the April 29, 2010 order. Among other things, the Mississippi PSC’s May 26, 2010 order approved an alternate construction cost cap of up to $2.88 billion (and any amounts that fall within specified exemptions from the cost cap; such exemptions include the costs of the lignite mine and equipment and the carbon dioxide pipeline facilities), subject to determinations by the Mississippi PSC that such costs in excess of $2.4 billion are prudent and required by the public convenience and necessity. On May 27, 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the order. On June 3, 2010, the Mississippi PSC issued the final certificate order which granted Mississippi Power’s motion and issued a CPCN authorizing acquisition, construction, and operation of the plant. The Kemper IGCC, subject to federal and state reviews and certain regulatory approvals, is expected to begin commercial operation in May 2014. See Note 3 to the financial statements of Southern Company and Mississippi Power in Item 8 herein for additional information.

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Employee Relations
The Southern Company system had a total of 25,940 employees on its payroll at December 31, 2010.
         
    Employees at December 31, 2010
 
Alabama Power
    6,552  
Georgia Power
    8,330  
Gulf Power
    1,330  
Mississippi Power
    1,280  
SCS
    4,465  
Southern Holdings*
     
Southern Nuclear
    3,676  
Southern Power**
     
Other
    307  
 
Total
    25,940  
 
 
*   Southern Holdings has agreements with SCS whereby all employee services are rendered at cost.
 
**   Southern Power has no employees. Southern Power has agreements with SCS and the traditional operating companies whereby employee services are rendered at amounts in compliance with FERC regulations.
The traditional operating companies have separate agreements with local unions of the IBEW generally covering wages, working conditions, and procedures for handling grievances and arbitration. These agreements apply with certain exceptions to operating, maintenance, and construction employees.
Alabama Power has an agreement with the IBEW covering wages and working conditions which is in effect through August 15, 2014.
Georgia Power has an agreement with the IBEW covering wages and working conditions, which is in effect through June 30, 2011. Upon notice given at least 60 days prior to that date, negotiations will be initiated with respect to agreement terms to be effective after such date.
Gulf Power has an agreement with the IBEW covering wages and working conditions, which is in effect through September 14, 2014.
Mississippi Power has an agreement with the IBEW covering wages and working conditions, which is in effect through August 15, 2014.
Southern Nuclear and the IBEW ratified a labor agreement for certain employees at Plants Hatch and Vogtle on May 21, 2009. The agreement is effective through June 30, 2011. Upon notice given at least 60 days prior to June 30, 2011, negotiations may be initiated with respect to a new agreement after such date. A five-year agreement between Southern Nuclear and the IBEW representing certain employees at Plant Farley was ratified on July 8, 2009. The agreement became effective on August 15, 2009 and will remain in effect through August 15, 2014.
Following certification of the United Government Security Officers of America (UGSOA) as the bargaining representative for Southern Nuclear Security Officers at Plant Farley in April 2010, negotiations continue between the UGSOA and Southern Nuclear. A collective bargaining agreement has not yet been ratified.
The agreements also make the terms of the pension plans for the companies discussed above subject to collective bargaining with the unions at either a five-year or a 10-year cycle, depending upon union and company actions.

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Item 1A. RISK FACTORS
In addition to the other information in this Form 10-K, including MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 of each registrant, and other documents filed by Southern Company and/or its subsidiaries with the SEC from time to time, the following factors should be carefully considered in evaluating Southern Company and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, Southern Company and/or its subsidiaries.
Risks Related to the Energy Industry
Southern Company and its subsidiaries are subject to substantial governmental regulation. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits, and certificates may result in substantial costs to Southern Company and its subsidiaries.
Southern Company and its subsidiaries, including the traditional operating companies and Southern Power, are subject to substantial regulation from federal, state, and local regulatory agencies. Southern Company and its subsidiaries are required to comply with numerous laws and regulations and to obtain numerous permits, approvals, and certificates from the governmental agencies that regulate various aspects of their businesses, including rates and charges, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices, including any changes in accounting standards, and the operation of fossil-fuel, hydroelectric, solar, and nuclear generating facilities. For example, the rates charged to wholesale customers by the traditional operating companies and by Southern Power must be approved by the FERC. These wholesale rates could be affected absent the ability to conduct business pursuant to FERC market-based rate authority. Additionally, the respective state PSCs must approve the traditional operating companies’ requested rates for retail customers. While the retail rates of the traditional operating companies are designed to provide for the full recovery of costs (including a reasonable return on invested capital), there can be no assurance that a state PSC, in a future rate proceeding, will not attempt to alter the timing or amount of certain costs for which recovery is sought or to modify the current authorized rate of return.
Southern Company and its subsidiaries believe the necessary permits, approvals, and certificates have been obtained for their respective existing operations and that their respective businesses are conducted in accordance with applicable laws; however, the impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries cannot now be predicted. Changes in regulation or the imposition of additional regulations could influence the operating environment of Southern Company and its subsidiaries and may result in substantial costs.
Risks Related to Environmental and Climate Change Legislation , Regulation, and Litigation
Southern Company’s, the traditional operating companies’, and Southern Power’s costs of compliance with environmental laws are significant. The costs of compliance with future environmental laws, including laws and regulations designed to address global climate change, renewable energy standards, air and water quality, coal combustion byproducts, and other matters and the incurrence of environmental liabilities could affect unit retirement decisions and negatively impact the net income, cash flows, and financial condition of Southern Company, the traditional operating companies, or Southern Power.
Southern Company, the traditional operating companies, and Southern Power are subject to extensive federal, state, and local environmental requirements which, among other things, regulate air emissions, water usage and discharges, and the management of hazardous and solid waste in order to adequately protect the environment. Compliance with these legal requirements requires Southern Company, the traditional operating companies, and Southern Power to commit significant expenditures for installation of pollution control equipment, environmental monitoring, emissions fees, and permits at all of their respective facilities. These expenditures are significant and Southern Company, the traditional operating companies, and Southern Power expect that they will increase in the future. Through 2010, Southern Company had invested approximately $8.1 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of $500 million, $1.3 billion, and $1.6 billion for 2010, 2009, and 2008, respectively. Southern Company expects that capital expenditures to comply with existing

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statutes and regulations will be $341 million, $427 million, and $452 million for 2011, 2012, and 2013, respectively. In addition, the Southern Company system currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $74 million to $289 million in 2011, $191 million to $670 million in 2012, and $476 million to $1.9 billion in 2013. The compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of any new or revised environmental statutes and regulations that are enacted, including proposed environmental legislation and regulations, the cost, availability, and existing inventory of emissions allowances, and the fuel mix of the electric utilities. The ultimate outcome cannot be determined at this time.
If Southern Company, any traditional operating company, or Southern Power fails to comply with environmental laws and regulations, even if caused by factors beyond its control, that failure may result in the assessment of civil or criminal penalties and fines. The EPA has filed civil actions against Alabama Power and Georgia Power and issued notices of violation to Gulf Power and Mississippi Power alleging violations of the new source review provisions of the Clean Air Act. Southern Company is also a party to suits alleging that emissions of carbon dioxide, a greenhouse gas, contribute to global climate change. An adverse outcome in any of these matters could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect unit retirement and replacement decisions, and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates for the traditional operating companies or market-based rates for Southern Power.
Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent.
Existing environmental laws and regulations may be revised or new laws and regulations related to global climate change, air quality, water quality, coal combustion byproducts, including coal ash, or other environmental and health concerns may be adopted or become applicable to Southern Company, the traditional operating companies, and Southern Power. For example, the regulation of greenhouse gas emissions through legislation or regulation has been, and continues to be, a focus of the current Administration. Although federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and/or energy efficiency standards failed to pass before the end of the 2010 session, such proposals are expected to continue to be considered in the future.
While climate legislation has yet to be adopted, the EPA is moving forward with the regulation of greenhouse gas emissions under the Clean Air Act. In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. In December 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has taken the position that when this rule became effective on January 2, 2011, carbon dioxide and other greenhouse gases became regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants and other commercial and industrial facilities. As a result, the construction of new facilities or the major modifications of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, known as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, which began on January 2, 2011, applies to sources and projects that would already be covered under PSD or Title V, whereas the second phase will begin on July 1, 2011 and applies to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. In addition to these rules, the EPA has entered into a proposed settlement agreement to issue standards of performance for greenhouse gas emissions from new and modified fossil-fuel fired electric generating units and greenhouse gas emissions guidelines for existing sources. Under the proposed settlement agreement, the EPA commits to issue the proposed standards by July 2011 and the final standards by May 2012.
International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. The December 2009 negotiations resulted in a nonbinding agreement that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The most recent round of negotiations took place in December 2010. The outcome and impact of the international negotiations cannot be determined at this time.

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Additionally, during 2010 the EPA proposed revisions, revised or issued additional regulations and designations with respect to air quality under the Clean Air Act, including eight-hour ozone standards, sulfur dioxide and nitrogen dioxide standards, a replacement to the Clean Air Interstate Rule relating to nitrogen oxide and sulfur dioxide emissions, and continues to work on a proposed Maximum Achievable Control Technology rule for coal and oil-fired electric generating units, which will likely address numerous hazardous air pollutants, including mercury.
The EPA is currently evaluating whether additional regulation of coal combustion byproducts (including coal ash and gypsum) is merited under federal solid and hazardous waste laws. On June 21, 2010, the EPA published a proposed rule that requested comments on two potential regulatory options for the management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of, or significant change to, existing storage facilities and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. On November 19, 2010, Southern Company filed publicly available comments with the EPA regarding the rulemaking proposal. These comments included a preliminary cost analysis under various alternatives in the rulemaking proposal. Southern Company regards these estimates as pre-screening figures that should be distinguished from the more formalized cost estimates Southern Company provides for projects that are more definite as to the elements and timing of execution. Although its analysis was preliminary, Southern Company concluded that potential compliance costs under the proposed rules would be substantially higher than the estimates reflected in the EPA’s rulemaking proposal.
The ultimate cost impact of such legislation, regulation, new interpretations, or international negotiations would depend upon the specific requirements enacted and cannot be determined at this time. Although the outcome of such legislation, regulation, new interpretations, or international negotiations cannot be determined at this time, legislation or regulation related to greenhouse gas emissions, renewable energy standards, air and water quality, coal combustion byproducts and other matters, individually or together, are likely to result in significant and additional compliance costs, including significant capital expenditures, and could result in additional operating restrictions. These costs will affect future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units of the traditional operating companies. Moreover, the traditional operating companies could incur additional material asset retirement obligations with respect to closing existing coal combustion byproduct storage facilities. Additional compliance costs and costs related to potential unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered from customers. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.
Risks Related to Southern Company and its Business
The regional power market in which Southern Company and its utility subsidiaries compete may have changing transmission regulatory structures, which could affect the ownership of these assets and related revenues and expenses.
The traditional operating companies currently own and operate transmission facilities as part of a vertically integrated utility. A small percentage of transmission revenues are collected through the wholesale electric tariff but the majority of transmission revenues are collected through retail rates. Ongoing FERC efforts that may potentially change the regulatory and/or operational structure of transmission could have an adverse impact on future revenues. In addition, pending FERC regulation pertaining to cost allocation could require the Southern Company and its utility subsidiaries to subsidize costs outside its service territory. The financial condition, net income, and cash flows of Southern Company and its utility subsidiaries could be adversely affected by pending or future changes in the federal regulatory or operational structure of transmission.
The net income of Southern Company, the traditional operating companies, and Southern Power could be negatively impacted by competitive activity in the wholesale electricity markets.
Competition at the wholesale level continues to evolve in the electricity markets. As a result of changes in federal law and regulatory policy, competition in the wholesale electricity markets has increased due to greater participation

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by traditional electricity suppliers, non-utility generators, IPPs, wholesale power marketers, and brokers. FERC rules related to transmission are designed to facilitate competition in the wholesale market on a nationwide basis by providing greater flexibility and more choices to wholesale power customers, including initiatives designed to promote and encourage the integration of renewable sources of supply. Moreover, along with transactions contemplating physical delivery of energy, futures contracts and derivatives are traded on various commodities exchanges. Southern Company, the traditional operating companies, and Southern Power cannot predict the impact of these and other such developments, nor can they predict the effect of changes in levels of wholesale supply and demand, which are typically driven by factors beyond their control.
Southern Company may be unable to meet its ongoing and future financial obligations and to pay dividends on its common stock if its subsidiaries are unable to pay upstream dividends or repay funds to Southern Company.
Southern Company is a holding company and, as such, Southern Company has no operations of its own. Substantially all of Southern Company’s consolidated assets are held by subsidiaries. Southern Company’s ability to meet its financial obligations and to pay dividends on its common stock is primarily dependent on the net income and cash flows of its subsidiaries and their ability to pay upstream dividends or to repay funds to Southern Company. Prior to funding Southern Company, Southern Company’s subsidiaries have regulatory restrictions and financial obligations that must be satisfied, including among others, debt service and preferred and preference stock dividends. Southern Company’s subsidiaries are separate legal entities and have no obligation to provide Southern Company with funds for its payment obligations.
The financial performance of Southern Company and its subsidiaries may be adversely affected if they are unable to successfully operate their facilities or perform certain corporate functions.
The financial performance of Southern Company and its subsidiaries depends on the successful operation of its subsidiaries’ electric generating, transmission, and distribution facilities. Operating these facilities involves many risks, including:
    operator error or failure of equipment or processes;
 
    operating limitations that may be imposed by environmental or other regulatory requirements;
 
    labor disputes;
 
    terrorist attacks;
 
    fuel or material supply interruptions;
 
    compliance with mandatory reliability standards, including mandatory cyber security standards;
 
    information technology system failure;
 
    cyber intrusion; and
 
    catastrophic events such as fires, earthquakes, explosions, floods, droughts, hurricanes, pandemic health events such as influenzas, or other similar occurrences.
A decrease or elimination of revenues from the electric generation, transmission, or distribution facilities or an increase in the cost of operating the facilities would reduce the net income and cash flows and could adversely impact the financial condition of the affected traditional operating company or Southern Power and of Southern Company.

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With respect to Southern Company’s investments in leverage leases, the recovery of its investment is dependent on the profitable operation of the leased assets by the respective lessees. A significant deterioration in the performance of the leased asset could result in the impairment of the related lease receivable.
The traditional operating companies and Southern Power could be subject to higher costs and penalties as a result of mandatory reliability standards.
As a result of the Energy Policy Act of 2005, owners and operators of bulk power transmission systems, including the traditional operating companies, are subject to mandatory reliability standards enacted by the North American Reliability Corporation and enforced by the FERC. Compliance with the mandatory reliability standards may subject the traditional operating companies, Southern Power, and Southern Company to higher operating costs and may result in increased capital expenditures. If any traditional operating company or Southern Power is found to be in noncompliance with the mandatory reliability standards, the traditional operating company and Southern Power could be subject to sanctions, including substantial monetary penalties.
The revenues of Southern Company, the traditional operating companies, and Southern Power depend in part on sales under PPAs. The failure of a counterparty to one of these PPAs to perform its obligations, or the failure to renew the PPAs, could have a negative impact on the net income and cash flows of the affected traditional operating company or Southern Power and of Southern Company.
Most of Southern Power’s generating capacity has been sold to purchasers under PPAs. In addition, the traditional operating companies enter into PPAs with non-affiliated parties. Revenues are dependent on the continued performance by the purchasers of their obligations under these PPAs. Even though Southern Power and the traditional operating companies have a rigorous credit evaluation process, the failure of one of the purchasers to perform its obligations could have a negative impact on the net income and cash flows of the affected traditional operating company or Southern Power and of Southern Company. Although these credit evaluations take into account the possibility of default by a purchaser, actual exposure to a default by a purchaser may be greater than the credit evaluation predicts. Additionally, neither Southern Power nor any traditional operating company can predict whether the PPAs will be renewed at the end of their respective terms or on what terms any renewals may be made. If a PPA is not renewed, a replacement PPA cannot be assured.
Southern Company, the traditional operating companies, and Southern Power may incur additional costs or delays in the construction of new plants or other facilities and may not be able to recover their investments. The facilities of the traditional operating companies and Southern Power require ongoing capital expenditures.
The businesses of the registrants require substantial capital expenditures for investments in new facilities and capital improvements to transmission, distribution, and generation facilities, including those to meet environmental standards. Certain of the traditional operating companies and Southern Power are in the process of constructing new generating facilities and adding environmental controls equipment at existing generating facilities. Southern Company intends to continue its strategy of developing and constructing other new facilities, including new nuclear generating, combined cycle, IGCC, and biomass generating units, expanding existing facilities, and adding environmental control equipment. These types of projects are long-term in nature and may involve facility designs that have not been finalized or previously constructed. The completion of these types of projects without delays or significant cost overruns is subject to substantial risks, including:
    shortages and inconsistent quality of equipment, materials, and labor;
 
    work stoppages;
 
    contractor or supplier non-performance under construction or other agreements;
 
    delays in or failure to receive necessary permits, approvals, and other regulatory authorizations;
 
    impacts of new and existing laws and regulations, including environmental laws and regulations;

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    continued public and policymaker support for such projects;
 
    adverse weather conditions;
 
    unforeseen engineering problems;
 
    changes in project design or scope;
 
    environmental and geological conditions;
 
    delays or increased costs to interconnect facilities to transmission grids; and
 
    unanticipated cost increases, including materials and labor.
In addition, with respect to the construction of new nuclear units, a major incident at a nuclear facility anywhere in the world could cause the NRC to delay or prohibit construction of new nuclear units. If a traditional operating company or Southern Power is unable to complete the development or construction of a facility or decides to delay or cancel construction of a facility, it may not be able to recover its investment in that facility and may incur substantial cancellation payments under equipment purchase orders or construction contracts. Even if a construction project is completed, the total costs may be higher than estimated and there is no assurance that the traditional operating company will be able to recover such expenditures through regulated rates. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues and may, in turn, adversely affect the net income and financial position of a traditional operating company or Southern Power and of Southern Company. Construction delays also may result in the loss of otherwise available investment tax credits and other tax incentives. Furthermore, if construction projects are not completed according to specification, a traditional operating company or Southern Power and Southern Company may incur liabilities and suffer reduced plant efficiency, higher operating costs, and reduced net income.
Once facilities come into commercial operation, ongoing capital expenditures are required to maintain reliable levels of operation. Significant portions of the traditional operating companies’ existing facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements, or to provide reliable operations.
Changes in technology may make Southern Company’s electric generating facilities owned by the traditional operating companies and Southern Power less competitive.
A key element of the business model of Southern Company, the traditional operating companies, and Southern Power is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, and solar cells. It is possible that advances in technology will reduce the cost of alternative methods of producing power to a level that is competitive with that of most central station power electric production. If this were to happen and if these technologies achieved economies of scale, the market share of Southern Company, the traditional operating companies, and Southern Power could be eroded, and the value of their respective electric generating facilities could be reduced. It is also possible that rapid advances in central station power generation technology could reduce the value of the current electric generating facilities owned by Southern Company, the traditional operating companies, and Southern Power. Changes in technology could also alter the channels through which electric customers buy or utilize power, which could reduce the revenues or increase the expenses of Southern Company, the traditional operating companies, or Southern Power.

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Operation of nuclear facilities involves inherent risks, including environmental, health, regulatory, terrorism, and financial risks, that could result in fines or the closure of Southern Company’s nuclear units owned by Alabama Power or Georgia Power and which may present potential exposures in excess of insurance coverage.
Alabama Power owns, and contracts for the operation of, two nuclear units and Georgia Power holds undivided interests in, and contracts for the operation of, four existing nuclear units and the construction of Plant Vogtle Units 3 and 4. The six existing units are operated by Southern Nuclear and represent approximately 3,680 megawatts, or 8.6%, of Southern Company’s generation capacity as of December 31, 2010. Nuclear facilities are subject to environmental, health, and financial risks such as on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential liabilities arising out of the operation of these facilities, and the threat of a possible terrorist attack. Alabama Power and Georgia Power maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that damages could exceed the amount of insurance coverage.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down any unit, depending upon its assessment of the severity of the situation, until compliance is achieved. NRC orders or regulations related to increased security measures and any future safety requirements promulgated by the NRC could require Alabama Power and Georgia Power to make substantial operating and capital expenditures at their nuclear plants. In addition, although Alabama Power, Georgia Power, and Southern Company have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could result in substantial costs to Alabama Power or Georgia Power and Southern Company. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.
In addition, potential terrorist threats and increased public scrutiny of utilities could result in increased nuclear licensing or compliance costs that are difficult or impossible to predict.
The generation operations and energy marketing operations of Southern Company, the traditional operating companies, and Southern Power are subject to risks, many of which are beyond their control, including changes in power prices and fuel costs, that may reduce Southern Company’s, the traditional operating companies’, and Southern Power’s revenues and increase costs.
The generation operations and energy marketing operations of Southern Company, the traditional operating companies, and Southern Power are subject to changes in power prices or fuel costs, which could increase the cost of producing power or decrease the amount Southern Company, the traditional operating companies, and Southern Power receive from the sale of power. The market prices for these commodities may fluctuate significantly over relatively short periods of time. In addition, the proportion of natural gas generation to the total fuel mix is likely to increase in the future. Southern Company, the traditional operating companies, and Southern Power attempt to mitigate risks associated with fluctuating fuel costs by passing these costs on to customers through the traditional operating companies’ fuel cost recovery clauses or through PPAs. Among the factors that could influence power prices and fuel costs are:
    prevailing market prices for coal, natural gas, uranium, fuel oil, biomass, and other fuels used in the generation facilities of the traditional operating companies and Southern Power including associated transportation costs, and supplies of such commodities;
 
    demand for energy and the extent of additional supplies of energy available from current or new competitors;
 
    liquidity in the general wholesale electricity market;
 
    weather conditions impacting demand for electricity;
 
    seasonality;

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    transmission or transportation constraints or inefficiencies;
 
    availability of competitively priced alternative energy sources;
 
    forced or unscheduled plant outages for the Southern Company system, its competitors, or third party providers;
 
    the financial condition of market participants;
 
    the economy in the service territory, the nation, and worldwide, including the impact of economic conditions on industrial and commercial demand for electricity and the worldwide demand for fuels;
 
    natural disasters, wars, embargos, acts of terrorism, and other catastrophic events; and
 
    federal, state, and foreign energy and environmental regulation and legislation.
Certain of these factors could increase the expenses of the traditional operating companies or Southern Power and Southern Company. For the traditional operating companies, such increases may not be fully recoverable through rates. Other of these factors could reduce the revenues of the traditional operating companies or Southern Power and Southern Company.
Historically, the traditional operating companies from time to time have experienced underrecovered fuel cost balances and deficits in their storm cost recovery reserve balances and may experience such balances in the future. While the traditional operating companies are generally authorized to recover underrecovered fuel costs through fuel cost recovery clauses and storm recovery costs through special rate provisions administered by the respective PSCs, recovery may be denied if costs are deemed to be imprudently incurred and delays in the authorization of such recovery could negatively impact the cash flows of the affected traditional operating company and Southern Company.
A downgrade in the credit ratings of Southern Company, the traditional operating companies, or Southern Power could negatively affect their ability to access capital at reasonable costs and/or could require Southern Company, the traditional operating companies, or Southern Power to post collateral or replace certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for Southern Company, the traditional operating companies, and Southern Power, including capital structure, regulatory environment, the ability to cover liquidity requirements, and other commitments for capital. Southern Company, the traditional operating companies, and Southern Power could experience a downgrade in their ratings if any of the rating agencies conclude that the level of business or financial risk of the industry or Southern Company, the traditional operating companies, or Southern Power has deteriorated. Changes in ratings methodologies by the agencies could also have a negative impact on credit ratings. If one or more rating agencies downgrade Southern Company, the traditional operating companies, or Southern Power, borrowing costs would increase, its pool of investors and funding sources would likely decrease, and, particularly for any downgrade to below investment grade, significant collateral requirements may be triggered in a number of contracts.
The use of derivative contracts by Southern Company and its subsidiaries in the normal course of business could result in financial losses that negatively impact the net income of Southern Company and its subsidiaries.
Southern Company and its subsidiaries, including the traditional operating companies and Southern Power, use derivative instruments, such as swaps, options, futures, and forwards, to manage their commodity and interest rate exposures and, to a lesser extent, engage in limited trading activities. Southern Company and its subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, limits, and procedures. These risk

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management policies, limits, and procedures might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, derivative contracts entered for hedging purposes might not off-set the underlying exposure being hedged as expected resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. The factors used in the valuation of these instruments become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Southern Company and its subsidiaries. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.
The traditional operating companies and Southern Power may not be able to obtain adequate fuel supplies, which could limit their ability to operate their facilities.
The traditional operating companies and Southern Power purchase fuel, including coal, natural gas, uranium, fuel oil, and biomass, from a number of suppliers. Disruption in the delivery of fuel, including disruptions as a result of, among other things, transportation delays, weather, labor relations, force majeure events, or environmental regulations affecting any of these fuel suppliers, could limit the ability of the traditional operating companies and Southern Power to operate their respective facilities, and thus reduce the net income of the affected traditional operating company or Southern Power and Southern Company.
The traditional operating companies are dependent on coal for much of their electric generating capacity. Each traditional operating company has coal supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal to the traditional operating companies. The suppliers under these agreements may experience financial or technical problems which inhibit their ability to fulfill their obligations to the traditional operating companies. In addition, the suppliers under these agreements may not be required to supply coal to the traditional operating companies under certain circumstances, such as in the event of a natural disaster. If the traditional operating companies are unable to obtain their coal requirements under these contracts, the traditional operating companies may be required to purchase their coal requirements at higher prices, which may not be fully recoverable through rates.
In addition, the traditional operating companies and Southern Power to a greater extent are dependent on natural gas for a portion of their electric generating capacity. Natural gas supplies can be subject to disruption in the event production or distribution is curtailed, such as in the event of a hurricane.
In addition, world market conditions for fuels can impact the availability of natural gas, coal, and uranium.
Demand for power could exceed supply capacity, resulting in increased costs for purchasing capacity in the open market or building additional generation capabilities.
Through the traditional operating companies and Southern Power, Southern Company is currently obligated to supply power to retail customers and wholesale customers under long-term PPAs. At peak times, the demand for power required to meet this obligation could exceed Southern Company’s available generation capacity. Market or competitive forces may require that the traditional operating companies or Southern Power purchase capacity on the open market or build additional generation capabilities. Because regulators may not permit the traditional operating companies to pass all of these purchase or construction costs on to their customers, the traditional operating companies may not be able to recover any of these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of purchased or constructed capacity and the traditional operating companies’ recovery in customers’ rates. Under Southern Power’s long-term fixed price PPAs, Southern Power would not have the ability to recover any of these costs. These situations could have negative impacts on net income and cash flows for the affected traditional operating company or Southern Power and Southern Company.

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Demand for power could decrease or fail to grow at expected rates, resulting in stagnant or reduced revenues, limited growth opportunities, and potentially stranded generation assets.
Southern Company, the traditional operating companies, and Southern Power each engage in a long-term planning process to determine the optimal mix and timing of new generation assets required to serve future load obligations. This planning process must look many years into the future in order to accommodate the long lead times associated with the permitting and construction of new generation facilities. Inherent risk exists in predicting demand this far into the future as these future loads are dependent on many uncertain factors, including regional economic conditions, customer usage patterns, efficiency programs, and customer technology adoption. Because regulators may not permit the traditional operating companies to adjust rates to recover the costs of new generation assets while such assets are being constructed, the traditional operating companies may not be able to fully recover these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of additional capacity and the traditional operating companies’ recovery in customers’ rates. Under Southern Power’s model of selling capacity and energy at negotiated market-based rates under long-term PPAs, Southern Power might not be able to fully execute its business plan if market prices drop below original forecasts. Southern Power may not be able to extend its existing PPAs or to find new buyers for existing generation assets as existing PPAs expire, or it may be forced to market these assets at prices lower than originally intended. These situations could have negative impacts on net income and cash flows for the affected traditional operating company or Southern Power and Southern Company.
The operating results of Southern Company, the traditional operating companies, and Southern Power are affected by weather conditions and may fluctuate on a seasonal and quarterly basis. In addition, significant weather events, such as hurricanes, tornadoes, floods, and droughts, or a terrorist attack could result in substantial damage to or limit the operation of the properties of the traditional operating companies and Southern Power and could negatively impact results of operation, financial condition, and liquidity.
Electric power supply is generally a seasonal business. In many parts of the country, demand for power peaks during the summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, the overall operating results of Southern Company, the traditional operating companies, and Southern Power in the future may fluctuate substantially on a seasonal basis. In addition, the traditional operating companies and Southern Power have historically sold less power when weather conditions are milder. Unusually mild weather in the future could reduce the revenues, net income, available cash, and borrowing ability of Southern Company, the traditional operating companies, and Southern Power.
In addition, volatile or significant weather events or a terrorist attack could result in substantial damage to the transmission and distribution lines of the traditional operating companies and the generating facilities of the traditional operating companies and Southern Power. The traditional operating companies and Southern Power have significant investments in the Atlantic and Gulf Coast regions which could be subject to major storm activity. Further, severe drought conditions can reduce the availability of water and restrict or prevent the operation of certain generating facilities.
Each traditional operating company maintains a reserve for property damage to cover the cost of damages from weather events to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property. In the event a traditional operating company experiences any of these weather events or any natural disaster, or other catastrophic event, such as a terrorist attack, recovery of costs in excess of reserves and insurance coverage is subject to the approval of its state PSC. While the traditional operating companies generally are entitled to recover prudently incurred costs incurred in connection with such an event, any denial by the applicable state PSC or delay in recovery of any portion of such costs could have a material negative impact on a traditional operating company’s and Southern Company’s results of operations, financial condition, and liquidity.
In addition, damages resulting from significant weather events within the service territory of any traditional operating company or affecting Southern Power’s customers may result in the loss of customers and reduced demand for electricity for extended periods. For example, Hurricane Katrina hit the Gulf Coast of Mississippi in August 2005 and caused substantial damage within Mississippi Power’s service territory. As of December 31, 2010, Mississippi Power had approximately 4.3% fewer retail customers as compared to pre-storm levels. Any significant

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loss of customers or reduction in demand for electricity could have a material negative impact on a traditional operating company’s, Southern Power’s, and Southern Company’s results of operations, financial condition, and liquidity.
Failure to attract and retain an appropriately qualified workforce could negatively impact Southern Company’s and its subsidiaries’ results of operations.
Events such as an aging workforce without appropriate replacements, mismatch of skillset to future needs, or unavailability of contract resources may lead to operating challenges or increased costs. Such operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development, especially with the workforce needs associated with new nuclear construction. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Southern Company and its subsidiaries’ ability to manage and operate their businesses. If Southern Company and its subsidiaries, including the traditional operating companies, are unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.
Risks Related to Market and Economic Volatility
The business of Southern Company, the traditional operating companies, and Southern Power is dependent on their ability to successfully access funds through capital markets and financial institutions. The inability of Southern Company, any traditional operating company, or Southern Power to access funds may limit its ability to execute its business plan by impacting its ability to fund capital investments or acquisitions that Southern Company, the traditional operating companies, or Southern Power may otherwise rely on to achieve future earnings and cash flows.
Southern Company, the traditional operating companies, and Southern Power rely on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from their respective operations. If Southern Company, any traditional operating company, or Southern Power is not able to access capital at competitive rates, its ability to implement its business plan will be limited by impacting its ability to fund capital investments or acquisitions that Southern Company, the traditional operating companies, or Southern Power may otherwise rely on to achieve future earnings and cash flows. In addition, Southern Company, the traditional operating companies, and Southern Power rely on committed bank lending agreements as back-up liquidity which allows them to access low cost money markets. Each of Southern Company, the traditional operating companies, and Southern Power believes that it will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions may increase its cost of borrowing or adversely affect its ability to raise capital through the issuance of securities or other borrowing arrangements or its ability to secure committed bank lending agreements used as back-up sources of capital. Such disruptions could include:
    an economic downturn or uncertainty;
 
    the bankruptcy or financial distress at an unrelated energy company or financial institution;
 
    capital markets volatility and interruption;
 
    market prices for electricity and gas;
 
    terrorist attacks or threatened attacks on Southern Company’s facilities or unrelated energy companies’ facilities;
 
    war or threat of war; or
 
    the overall health of the utility and financial institution industries.

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Market performance and other changes may decrease the value of benefit plans and nuclear decommissioning trust assets or may increase plan costs, which then could require significant additional funding.
The performance of the capital markets affects the values of the assets held in trust under Southern Company’s pension and postretirement benefit plans and the assets held in trust to satisfy obligations to decommission Alabama Power’s and Georgia Power’s nuclear plants. Southern Company, Alabama Power, and Georgia Power have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below projected return rates. A decline in the market value of these assets, as has been experienced in prior periods, may increase the funding requirements relating to Southern Company’s benefit plan liabilities and Alabama Power’s and Georgia Power’s nuclear decommissioning obligations. Additionally, changes in interest rates affect the liabilities under Southern Company’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension benefit plans. Southern Company and its subsidiaries are also facing rising medical benefit costs, including the current costs for active and retired employees. It is possible that these costs may increase at a rate that is significantly higher than anticipated. If Southern Company is unable to successfully manage benefit plan assets and medical benefit costs and Alabama Power and Georgia Power are unable to successfully manage the nuclear decommissioning trust funds, results of operations and financial position could be negatively affected. Additionally, Southern Company and its subsidiaries may also be affected by healthcare legislation.
Southern Company, the traditional operating companies, and Southern Power are subject to risks associated with a changing economic environment, which could impact their ability to obtain adequate insurance and the financial stability of the customers of the traditional operating companies and Southern Power.
The financial condition of some insurance companies, the threat of terrorism, and the hurricanes that affected the Gulf Coast, among other things, have had disruptive effects on the insurance industry. The availability of insurance covering risks that Southern Company, the traditional operating companies, Southern Power, and their respective competitors typically insure against may decrease, and the insurance that Southern Company, the traditional operating companies, and Southern Power are able to obtain may have higher deductibles, higher premiums, and more restrictive policy terms.
Additionally, Southern Company, the traditional operating companies, and Southern Power are exposed to risks related to general economic conditions in their applicable service territory and are thus impacted by the economic cycles of the customers each serves. Any economic downturn or disruption of financial markets could negatively affect the financial stability of the customers and counterparties of the traditional operating companies and Southern Power. As territories served by the traditional operating companies and Southern Power experience economic downturns, energy consumption patterns may change and revenues may be negatively impacted. Additionally, customers could voluntarily reduce their consumption of electricity in response to decreases in their disposable income or individual conservation efforts. If commercial and industrial customers experience economic downturns, their consumption of electricity may decline. As a result, revenues may be negatively impacted.
Further, the results of operations of the traditional operating companies and Southern Power are affected by customer growth in their applicable service territory. Customer growth and customer usage can be affected by economic factors in the service territory of the traditional operating companies and Southern Power and elsewhere, including, for example, job and income growth, housing starts, and new home prices. A population decline and/or business closings in the territory served by the traditional operating companies or Southern Power or slower than anticipated customer growth as a result of the recent recession or otherwise could also have a negative impact on revenues and could result in greater expense for uncollectible customer balances.
As with other parts of the country, the territories served by the traditional operating companies and Southern Power have been impacted by the recent economic recession. The traditional operating companies have experienced some decline in the rate of residential and commercial sales growth, and also have experienced declining sales to commercial and industrial customers due to the recent economic recession. Southern Power is expected to continue to experience reduced future revenues for its requirements customers due to the recent economic recession. The timing and extent of the recovery cannot be predicted.

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These and the other factors discussed above could adversely affect Southern Company’s, the traditional operating companies’, and Southern Power’s level of future net income.
Energy conservation and energy price increases could negatively impact financial results.
A number of regulatory and legislative bodies have proposed or introduced requirements and/or incentives to reduce energy consumption by certain dates. Conservation programs could impact the financial results of Southern Company, the traditional operating companies, and Southern Power in different ways. To the extent conservation results in reduced energy demand or significantly slows the growth in demand, the value of wholesale generation assets of the traditional operating companies and Southern Power and other unregulated business activities could be adversely impacted. In addition, conservation could negatively impact the traditional operating companies depending on the regulatory treatment of the associated impacts. If any traditional operating company is required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact on such traditional operating company and Southern Company. Southern Company, the traditional operating companies, and Southern Power could also be impacted if any future energy price increases result in a decrease in customer usage. Southern Company, the traditional operating companies, and Southern Power are unable to determine what impact, if any, conservation and increases in energy prices will have on financial condition or results of operations.
Item 1B. UNRESOLVED STAFF COMMENTS.
None.

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Item 2. PROPERTIES
Electric Properties
The traditional operating companies, Southern Power, Southern Renewable Energy, and SEGCO, at December 31, 2010, owned and/or operated 33 hydroelectric generating stations, 34 fossil fuel generating stations, three nuclear generating stations, and 12 combined cycle/cogeneration stations, one solar facility, and one landfill gas facility. The amounts of capacity for each company are shown in the table below.
             
        Nameplate
Generating Station   Location   Capacity (1)
 
 
      (Kilowatts)  
FOSSIL STEAM
           
Gadsden
  Gadsden, AL     120,000  
Gorgas
  Jasper, AL     1,221,250  
Barry
  Mobile, AL     1,525,000  
Greene County
  Demopolis, AL     300,000 (2)
Gaston Unit 5
  Wilsonville, AL     880,000  
Miller
  Birmingham, AL     2,532,288 (3)
 
           
Alabama Power Total
        6,578,538  
 
           
 
           
Bowen
  Cartersville, GA     3,160,000  
Branch
  Milledgeville, GA     1,539,700  
Hammond
  Rome, GA     800,000  
Kraft
  Port Wentworth, GA     281,136  
McDonough (4)
  Atlanta, GA     490,000  
McIntosh
  Effingham County, GA     163,117  
McManus
  Brunswick, GA     115,000  
Mitchell
  Albany, GA     125,000  
Scherer
  Macon, GA     750,924 (5)
Wansley
  Carrollton, GA     925,550 (6)
Yates
  Newnan, GA     1,250,000  
 
           
Georgia Power Total
        9,600,427  
 
           
 
           
Crist
  Pensacola, FL     970,000  
Daniel
  Pascagoula, MS     500,000 (7)
Lansing Smith
  Panama City, FL     305,000  
Scholz
  Chattahoochee, FL     80,000  
Scherer Unit 3
  Macon, GA     204,500 (5)
 
           
Gulf Power Total
        2,059,500  
 
           
 
           
Daniel
  Pascagoula, MS     500,000 (7)
Eaton
  Hattiesburg, MS     67,500  
Greene County
  Demopolis, AL     200,000 (2)
Sweatt
  Meridian, MS     80,000  
Watson
  Gulfport, MS     1,012,000  
 
           
Mississippi Power Total
        1,859,500  
 
           
 
           
Gaston Units 1-4
  Wilsonville, AL        
SEGCO Total
        1,000,000 (8)
 
           
Total Fossil Steam
        21,097,965  
 
           
 
           
NUCLEAR STEAM
           
Farley
  Dothan, AL        
Alabama Power Total
        1,720,000  
 
           
 
           
Hatch
  Baxley, GA     899,612 (9)
Vogtle
  Augusta, GA     1,060,240 (10)
 
           
Georgia Power Total
        1,959,852  
 
           
Total Nuclear Steam
        3,679,852  
 
           
 
           
COMBUSTION TURBINES
           
Greene County
  Demopolis, AL        
Alabama Power Total
        720,000  
 
           
 
           
Boulevard
  Savannah, GA     59,100  
Bowen
  Cartersville, GA     39,400  
Intercession City
  Intercession City, FL     47,667 (11)
Kraft
  Port Wentworth, GA     22,000  
McDonough
  Atlanta, GA     78,800  
McIntosh Units 1 through 8
  Effingham County, GA     640,000  
McManus
  Brunswick, GA     481,700  
Mitchell
  Albany, GA     118,200  
Robins
  Warner Robins, GA     158,400  
Wansley
  Carrollton, GA     26,322 (6)
Wilson
  Augusta, GA     354,100  
 
           
Georgia Power Total
        2,025,689  
 
           
 
           
Lansing Smith Unit A
  Panama City, FL     39,400  
Pea Ridge Units 1-3
  Pea Ridge, FL     15,000  
 
           
Gulf Power Total
        54,400  
 
           
 
           
Chevron Cogenerating Station
  Pascagoula, MS     147,292 (12)
Sweatt
  Meridian, MS     39,400  

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        Nameplate
Generating Station   Location   Capacity (1)
 
 
      (Kilowatts)  
Watson
  Gulfport, MS     39,360  
 
           
Mississippi Power Total
        226,052  
 
           
 
           
Dahlberg
  Jackson County, GA     756,000  
Oleander
  Cocoa, FL     791,301  
Rowan
  Salisbury, NC     455,250  
West Georgia
  Thomaston, GA     668,800  
 
           
Southern Power Total
        2,671,351  
 
           
 
           
Gaston (SEGCO)
  Wilsonville, AL     19,680 (8)
 
           
Total Combustion Turbines
        5,717,172  
 
           
 
           
COGENERATION
           
Washington County
  Washington County, AL     123,428  
GE Plastics Project
  Burkeville, AL     104,800  
Theodore
  Theodore, AL     236,418  
 
           
Total Cogeneration
        464,646  
 
           
 
           
COMBINED CYCLE
           
Barry
  Mobile, AL        
Alabama Power Total
        1,070,424  
 
           
McIntosh Units 10&11
  Effingham County, GA        
Georgia Power Total
        1,318,920  
 
           
Smith
  Lynn Haven, FL        
Gulf Power Total
        545,500  
 
           
Daniel (Leased)
  Pascagoula, MS        
Mississippi Power Total
        1,070,424  
 
           
Franklin
  Smiths, AL     1,857,820  
Harris
  Autaugaville, AL     1,318,920  
Rowan
  Salisbury, NC     530,550  
Stanton Unit A
  Orlando, FL     428,649 (13)
Wansley
  Carrollton, GA     1,073,000  
 
           
Southern Power Total
        5,208,939  
 
           
Total Combined Cycle
        9,214,207  
 
           
 
           
HYDROELECTRIC FACILITIES
           
Bankhead
  Holt, AL     53,985  
Bouldin
  Wetumpka, AL     225,000  
Harris
  Wedowee, AL     132,000  
Henry
  Ohatchee, AL     72,900  
Holt
  Holt, AL     46,944  
Jordan
  Wetumpka, AL     100,000  
Lay
  Clanton, AL     177,000  
Lewis Smith
  Jasper, AL     157,500  
Logan Martin
  Vincent, AL     135,000  
Martin
  Dadeville, AL     182,000  
Mitchell
  Verbena, AL     170,000  
Thurlow
  Tallassee, AL     81,000  
Weiss
  Leesburg, AL     87,750  
Yates
  Tallassee, AL     47,000  
 
           
Alabama Power Total
        1,668,079  
 
           
 
           
Bartletts Ferry
  Columbus, GA     173,000  
Goat Rock
  Columbus, GA     38,600  
Lloyd Shoals
  Jackson, GA     14,400  
Morgan Falls
  Atlanta, GA     16,800  
North Highlands
  Columbus, GA     29,600  
Oliver Dam
  Columbus, GA     60,000  
Rocky Mountain
  Rome, GA     215,256 (14)
Sinclair Dam
  Milledgeville, GA     45,000  
Tallulah Falls
  Clayton, GA     72,000  
Terrora
  Clayton, GA     16,000  
Tugalo
  Clayton, GA     45,000  
Wallace Dam
  Eatonton, GA     321,300  
Yonah
  Toccoa, GA     22,500  
6 Other Plants
        18,080  
 
           
Georgia Power Total
        1,087,536  
 
           
Total Hydroelectric Facilities
        2,755,615  
 
           
 
           
SOLAR
           
Cimarron
  Springer, NM        
Southern Renewable Total
        30,000 (15)
 
           
 
           
LANDFILL GAS
           
Perdido
  Escambia County, FL        
Gulf Power Total
        3,200  
 
           
 
Total Generating Capacity
        42,962,657  
 
           
 
Notes:
 
(1)   See “Jointly-Owned Facilities” herein for additional information.
 
(2)   Owned by Alabama Power and Mississippi Power as tenants in common in the proportions of 60% and 40%, respectively.
 
(3)   Capacity shown is Alabama Power’s portion (91.84%) of total plant capacity.

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(4)   McDonough Units 1 and 2 are scheduled to be retired in April 2012 and October 2011, respectively.
 
(5)   Capacity shown for Georgia Power is 8.4% of Units 1 and 2 and 75% of Unit 3. Capacity shown for Gulf Power is 25% of Unit 3.
 
(6)   Capacity shown is Georgia Power’s portion (53.5%) of total plant capacity.
 
(7)   Represents 50% of the plant which is owned as tenants in common by Gulf Power and Mississippi Power.
 
(8)   SEGCO is jointly-owned by Alabama Power and Georgia Power. See BUSINESS in Item 1 herein for additional information.
 
(9)   Capacity shown is Georgia Power’s portion (50.1%) of total plant capacity.
 
(10)   Capacity shown is Georgia Power’s portion (45.7%) of total plant capacity.
 
(11)   Capacity shown represents 33 1/3% of total plant capacity. Georgia Power owns a 1/3 interest in the unit with 100% use of the unit from June through September. Progress Energy Florida operates the unit.
 
(12)   Generation is dedicated to a single industrial customer.
 
(13)   Capacity shown is Southern Power’s portion (65%) of total plant capacity.
 
(14)   Capacity shown is Georgia Power’s portion (25.4%) of total plant capacity. OPC operates the plant.
 
(15)   The Cimarron solar facility is owned by an indirect subsidiary of Southern Renewable Energy. The kilowatts shown represents 100% of the facility’s capacity.
Except as discussed below under “Titles to Property,” the principal plants and other important units of the traditional operating companies, Southern Power, and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition.
Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States is paying a use fee over a 40-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 2010, the unamortized portion of this cost was approximately $20.6 million.
In 2010, the maximum demand on the traditional operating companies, Southern Power, and SEGCO was 36,321,000 kilowatts and occurred on July 26, 2010. The all-time maximum demand of 38,777,000 kilowatts on the traditional operating companies, Southern Power, and SEGCO occurred on August 22, 2007. These amounts exclude demand served by capacity retained by MEAG Power, OPC, and SEPA. The reserve margin for the traditional operating companies, Southern Power, and SEGCO in 2010 was 23%. See SELECTED FINANCIAL DATA in Item 6 herein for additional information on peak demands for each registrant.

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Jointly-Owned Facilities
Alabama Power, Georgia Power, and Southern Power have undivided interests in certain generating plants and other related facilities to or from non-affiliated parties. The percentages of ownership are as follows:
                                                                                                 
            Percentage Ownership
                                                            Progress                          
    Total     Alabama     Power     Georgia             MEAG             Energy     Southern                    
    Capacity     Power     South     Power     OPC     Power     Dalton     Florida     Power     OUC     FMPA     KUA  
    (Megawatts)  
Plant Miller
Units 1 and 2
    1,320       91.8 %     8.2 %     %     %     %     %     %     %     %     %     %
Plant Hatch
    1,796                   50.1       30.0       17.7       2.2                                
Plant Vogtle
    2,320                   45.7       30.0       22.7       1.6                                
Plant Scherer
Units 1 and 2
    1,636                   8.4       60.0       30.2       1.4                                
Plant Wansley
    1,779                   53.5       30.0       15.1       1.4                                
Rocky Mountain
    848                   25.4       74.6                                            
Intercession City, FL
    143                   33.3                         66.7                          
Plant Stanton A
    660                                                 65 %     28 %     3.5 %     3.5 %
                         
Alabama Power and Georgia Power have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain and Intercession City) as agent for the joint owners. SCS provides operation and maintenance services for Plant Stanton A.
In addition, Georgia Power has commitments regarding a portion of a five percent interest in Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG Power’s bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit’s variable operating costs. Except for the portion of the capacity payments related to the Georgia PSC’s disallowances of Plant Vogtle Units 1 and 2 costs, the cost of such capacity and energy is included in purchased power from non-affiliates in Georgia Power’s statements of income in Item 8 herein. Also see Note 7 to the financial statements of Georgia Power under “Commitments — Purchased Power Commitments” in Item 8 herein for additional information.
Titles to Property
The traditional operating companies’, Southern Power’s, and SEGCO’s interests in the principal plants (other than certain pollution control facilities, combined cycle units at Plant Daniel leased by Mississippi Power, and the land on which five combustion turbine generators of Mississippi Power are located, which is held by easement) and other important units of the respective companies are owned in fee by such companies, subject only to the liens pursuant to pollution control revenue bonds of Alabama Power and Gulf Power on specific pollution control facilities. See Note 6 to the financial statements of Southern Company, Alabama Power, and Gulf Power under “Assets Subject to Lien” and Note 7 to the financial statements of Mississippi Power under “Operating Leases — Plant Daniel Combined Cycle Generating Units” in Item 8 herein for additional information. The traditional operating companies own the fee interests in certain of their principal plants as tenants in common. See “Jointly-Owned Facilities” herein for additional information. Properties such as electric transmission and distribution lines and steam heating mains are constructed principally on rights-of-way which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements.

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Item 3. LEGAL PROCEEDINGS
(1) United States of America v. Alabama Power (United States District Court for the Northern District of Alabama)
       United States of America v. Georgia Power (United States District Court for the Northern District of Georgia)
See Note 3 to the financial statements of Southern Company and each traditional operating company under “Environmental Matters – New Source Review Actions” in Item 8 herein for information.
(2) Environmental Remediation
See Note 3 to the financial statements of Southern Company, Georgia Power, Gulf Power, and Mississippi Power under “Environmental Matters – Environmental Remediation” and Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Environmental Compliance Overview Plan” in Item 8 herein for information related to environmental remediation.
(3) Right of Way Litigation
See Note 3 to the financial statements of Southern Company and Mississippi Power under “Right of Way Litigation” in Item 8 herein for information.
See Note 3 to the financial statements of each registrant in Item 8 herein for descriptions of additional legal and administrative proceedings discussed therein.

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EXECUTIVE OFFICERS OF SOUTHERN COMPANY
(Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2010.
Thomas A. Fanning
Chairman, President, Chief Executive Officer, and Director
Age 53
Elected in 2003. Chairman and Chief Executive Officer since December 1, 2010 and President since August 1, 2010. Previously served as Executive Vice President and Chief Operating Officer from February 2008 through July 31, 2010. He also served as Executive Vice President and Chief Financial Officer from May 2007 through January 2008 and Executive Vice President, Chief Financial Officer, and Treasurer from April 2003 to May 2007.
Art P. Beattie
Executive Vice President and Chief Financial Officer
Age 56
Elected in 2010. Executive Vice President and Chief Financial Officer since August 13, 2010. Previously served as Executive Vice President, Chief Financial Officer, and Treasurer of Alabama Power from February 2005 through August 12, 2010 and Vice President and Comptroller of Alabama Power from 1998 through January 2005.
W. Paul Bowers
Executive Vice President
Age 54
Elected in 2001. Chief Executive Officer, President and Director of Georgia Power since December 31, 2010 and Chief Operating Officer of Georgia Power from August 13, 2010 to December 31, 2010. He previously served as Executive Vice President and Chief Financial Officer of Southern Company from February 2008 to August 12, 2010. He also served as Executive Vice President of Southern Company from May 2007 to February 2008 and as President of Southern Company Generation, a business unit of Southern Company, and Executive Vice President of SCS from May 2001 through January 2008.
Mark A. Crosswhite
President and Chief Executive Officer of Gulf Power
Age 48
Elected in 2010. President, Chief Executive Officer, and Director of Gulf Power since January 1, 2011. Previously served as Executive Vice President of External Affairs at Alabama Power from February 2008 through December 2010 and Senior Vice President and Counsel of Alabama Power from July 2006 through January 2008. He also served as Vice President of SCS from March 2004 through January 2008.
Edward Day, IV
President and Chief Executive Officer of Mississippi Power
Age 50
Elected in 2010. President, Chief Executive Officer, and Director of Mississippi Power since August 13, 2010. Previously served as Executive Vice President for Engineering and Construction Services at Southern Company Generation, a business unit of Southern Company, from May 2003 to August 12, 2010.
G. Edison Holland, Jr.
Executive Vice President, General Counsel, and Secretary
Age 58
Elected in 2001. Executive Vice President and General Counsel since April 2001.
Charles D. McCrary
Executive Vice President
Age 59
Elected in 1998. Executive Vice President since February 2002. He also serves as President, Chief Executive Officer, and Director of Alabama Power since October 2001.

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James H. Miller, III
President and Chief Executive Officer of Southern Nuclear
Age 61
Elected in 2008. President and Chief Executive Officer of Southern Nuclear since August 27, 2008. Previously served as Senior Vice President and General Counsel of Georgia Power from March 2004 through August 2008.
Susan N. Story
Executive Vice President
Age 50
Elected in 2003. President and Chief Executive Officer of SCS since January 1, 2011. Previously served as President, Chief Executive Officer, and Director of Gulf Power from April 2003 through December 2010.
Anthony J. Topazi
Executive Vice President and Chief Operating Officer
Age 60
Elected in 2003. Executive Vice President and Chief Operating Officer since August 13, 2010. Previously served as President, Chief Executive Officer, and Director of Mississippi Power from January 2004 through August 12, 2010.
Christopher C. Womack
Executive Vice President
Age 52
Elected in 2008. Executive Vice President and President of External Affairs since January 1, 2009. Previously served as Executive Vice President of External Affairs of Georgia Power from March 2006 through December 2008 and Senior Vice President of Fossil and Hydro Generation and Senior Production Officer of Georgia Power from December 2001 to February 2006.
The officers of Southern Company were elected for a term running from the first meeting of the directors following the last annual meeting (May 26, 2010) for one year until the first board meeting after the next annual meeting or until their successors are elected and have qualified, except for Ms. Story, whose election was effective January 1, 2011, and Messrs. Beattie, and Topazi, whose elections were effective August 13, 2010. Mr. Fanning was elected President effective August 1, 2010 and Chairman, President, Chief Executive Officer, and Director effective December 1, 2010.

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EXECUTIVE OFFICERS OF ALABAMA POWER
(Identification of executive officers of Alabama Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2010.
Charles D. McCrary
President, Chief Executive Officer, and Director
Age 59
Elected in 2001. President, Chief Executive Officer, and Director since October 2001; Executive Vice President of Southern Company since February 2002.
Philip C. Raymond
Executive Vice President, Chief Financial Officer, and Treasurer
Age 51
Elected in 2010. Executive Vice President, Chief Financial Officer and Treasurer since August 13, 2010. Previously served as Vice President and Chief Financial Officer of Gulf Power from May 2008 to August 12, 2010 and as Vice President and Comptroller of Alabama Power from January 2005 to April 2008.
Zeke W. Smith
Executive Vice President
Age 51
Elected in 2010. Executive Vice President of External Affairs since November 8, 2010. Previously served as Vice President of Regulatory Services and Financial Planning from February 2005 to November 2010.
Steven R. Spencer
Executive Vice President
Age 55
Elected in 2001. Executive Vice President of the Customer Service Organization since February 1, 2008. Previously served as Executive Vice President of External Affairs from 2001 through January 2008.
Theodore J. McCullough
Senior Vice President and Senior Production Officer
Age 47
Elected in 2010. Senior Vice President and Senior Production Officer since June 30, 2010. Previously served as Vice President and Senior Production Officer of Gulf Power from September 2007 until June 2010, and Manager of Georgia Power’s Plant Branch from December 2003 to August 2007.
The officers of Alabama Power were elected for a term running from the meeting of the directors held on April 23, 2010 for one year or until their successors are elected and have qualified, except for Messrs. Raymond, Smith, and McCullough, whose elections were effective August 13, 2010, November 8, 2010, and June 30, 2010, respectively.

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EXECUTIVE OFFICERS OF GEORGIA POWER
(Identification of executive officers of Georgia Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2010.
W. Paul Bowers
President, Chief Executive Officer, and Director
Age 54
Elected in 2010. Chief Executive Officer, President, and Director since December 31, 2010 and Chief Operating Officer of Georgia Power from August 13, 2010 to December 31, 2010. He previously served as Executive Vice President and Chief Financial Officer of Southern Company from February 2008 to August 12, 2010. He also served as Executive Vice President of Southern Company from May 2007 to February 2008 and as President of Southern Company Generation, a business unit of Southern Company, and Executive Vice President of SCS from May 2001 through January 2008.
W. Craig Barrs
Executive Vice President
Age 53
Elected in 2008. Executive Vice President of External Affairs since January 2010. Previously served as Senior Vice President of External Affairs from January 2009 to January 2010, Vice President of Governmental and Regulatory Affairs from April 2008 to December 2008, Vice President of the Coastal Region from August 2006 to March 2008, and President and Chief Executive Officer of Savannah Electric and Power Company from January 2006 until its merger with and into Georgia Power which was completed in July 2006.
Mickey A. Brown
Executive Vice President
Age 63
Elected in 2001. Executive Vice President of the Customer Service Organization since January 2005.
Ronnie R. Labrato
Executive Vice President, Chief Financial Officer, and Treasurer
Age 57
Elected in 2009. Executive Vice President, Chief Financial Officer, and Treasurer since April 2009. Previously served as Vice President of Internal Auditing at SCS from April 2008 to March 2009 and Vice President and Chief Financial Officer of Gulf Power from July 2001 to March 2008.
Joseph A. Miller
Executive Vice President
Age 49
Elected in 2009. Executive Vice President of Nuclear Development since May 2009. Also serves as Executive Vice President of Nuclear Development at Southern Nuclear since February 2006. Previously served as Vice President of Government Relations at SCS from May 1999 to January 2006.
Thomas P. Bishop
Senior Vice President, Chief Compliance Officer, and General Counsel
Age 50
Elected in 2008. Senior Vice President, Chief Compliance Officer, and General Counsel since September 2008. Previously served as Vice President and Associate General Counsel for SCS from July 2004 to September 2008.

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Stan W. Connally
Senior Vice President and Chief Production Officer
Age 41
Elected in 2010. Senior Vice President and Chief Production Officer since August 1, 2010. Previously served as Manager of Alabama Power’s Plant Barry from August 2007 through July 2010 and Manager of Mississippi Power’s Plant Daniel from November 2004 through August 2007.
The officers of Georgia Power were elected for a term running from the meeting of the directors held on May 19, 2010 for one year or until their successors are elected and have qualified, except for Messrs. Bowers and Connally. Mr. Bowers was elected Chief Operating Officer effective August 13, 2010 and Chief Executive Officer, President, and Director effective December 31, 2010. Mr. Connally was elected effective August 1, 2010.

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EXECUTIVE OFFICERS OF MISSISSIPPI POWER
(Identification of executive officers of Mississippi Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2010.
Edward Day, VI
President, Chief Executive Officer, and Director
Age 50
Elected in 2010. President, Chief Executive Officer, and Director since August 13, 2010. Previously served as Executive Vice President for Engineering and Construction Services at Southern Company Generation, a business unit of Southern Company, from May 2003 to August 12, 2010.
Thomas O. Anderson, IV
Vice President
Age 51
Elected in 2009. Vice President of Generation Development since July 2009. Previously served as Project Director, Mississippi Power Generation Development from March 2008 to July 2009; Project Manager, Southern Power Generation from June 2007 to March 2008; and Generation Development Manager, SCS Generation Development from September 1998 to June 2007.
John W. Atherton
Vice President
Age 50
Elected in 2004. Vice President of External Affairs since January 2005.
Moses H. Feagin
Vice President, Treasurer, and
Chief Financial Officer
Age 46
Elected in 2010. Vice President, Treasurer, and Chief Financial Officer since August 13, 2010. Previously served as Vice President and Comptroller of Alabama Power from May 2008 to August 12, 2010, and Comptroller of Mississippi Power from March 2005 to May 2008.
Donald R. Horsley
Vice President
Age 56
Elected in 2006. Vice President of Customer Services Organization since April 2006. Previously served as Vice President of Transmission at Alabama Power from March 2005 to March 2006.
R. Allen Reaves
Vice President
Age 51
Elected in 2010. Vice President and Senior Production Officer since August 1, 2010. Previously served as Manager of Mississippi Power’s Plant Daniel from September 2007 through July 2010 and Site Manager for Southern Power’s Plant Franklin, from March 2006 to September 2007.
The officers of Mississippi Power were elected for a term running from the meeting of the directors held on April 8, 2010 for one year or until their successors are elected and have qualified, except for Messrs. Day and Feagin, whose elections were effective August 13, 2010, and Mr. Reaves, whose election was effective August 1, 2010.

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PART II
Item 5.   MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
(a)(1) The common stock of Southern Company is listed and traded on the New York Stock Exchange. The common stock is also traded on regional exchanges across the United States. The high and low stock prices as reported on the New York Stock Exchange for each quarter of the past two years were as follows:
                 
     
    High   Low
2010
               
First Quarter
  $ 33.73       30.85  
Second Quarter
    35.45       32.04  
Third Quarter
    37.73       33.00  
Fourth Quarter
    38.62       37.10  
 
               
2009
               
First Quarter
  $ 37.62     $ 26.48  
Second Quarter
    32.05       27.19  
Third Quarter
    32.67       30.27  
Fourth Quarter
    34.47       30.89  
 
There is no market for the other registrants’ common stock, all of which is owned by Southern Company.
(a)(2) Number of Southern Company’s common stockholders of record at January 31, 2011: 159,733
Each of the other registrants have one common stockholder, Southern Company.
(a)(3) Dividends on each registrant’s common stock are payable at the discretion of their respective board of directors. The dividends on common stock declared by Southern Company and the traditional operating companies to their stockholder(s) for the past two years were as follows:
                     
     
Registrant   Quarter   2010   2009
        (in thousands)
Southern Company
  First   $ 359,144     $ 326,780  
 
  Second     375,865       343,446  
 
  Third     378,939       348,702  
 
  Fourth     382,440       350,538  
 
                   
Alabama Power
  First     135,675       130,700  
 
  Second     135,675       130,700  
 
  Third     135,675       130,700  
 
  Fourth     178,675       130,700  
 
                   
Georgia Power
  First     205,000       184,725  
 
  Second     205,000       184,725  
 
  Third     205,000       184,725  
 
  Fourth     205,000       184,725  
 
                   
Gulf Power
  First     26,075       22,325  
 
  Second     26,075       22,325  
 
  Third     26,075       22,325  
 
  Fourth     26,075       22,325  
 
                   
Mississippi Power
  First     17,150       17,125  
 
  Second     17,150       17,125  
 
  Third     17,150       17,125  
 
  Fourth     17,150       17,125  

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In 2010 and 2009, Southern Power paid dividends to Southern Company as follows:
                     
     
Registrant   Quarter   2010   2009
        (in thousands)
Southern Power
  First   $ 26,775     $ 26,525  
 
  Second     26,775       26,525  
 
  Third     26,775       26,525  
 
  Fourth     26,775       26,525  
 
The dividend paid per share of Southern Company’s common stock was 43.75¢ for the first quarter of 2010 and 45.50¢ for the second, third, and fourth quarters of 2010. In 2009, Southern Company paid a dividend per share of 42¢ in the first quarter of 2009 and 43.75¢ for the second, third, and fourth quarters of 2009.
The traditional operating companies and Southern Power can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
Southern Power’s credit facility and senior note indenture contain potential limitations on the payment of common stock dividends. At December 31, 2010, Southern Power was in compliance with the conditions of this credit facility and thus had no restrictions on its ability to pay common stock dividends. See Note 8 to the financial statements of Southern Company under “Common Stock Dividend Restrictions” and Note 6 to the financial statements of Southern Power under “Dividend Restrictions” in Item 8 herein for additional information regarding these restrictions.
(b) Use of Proceeds
Not applicable.
(c) Issuer Purchases of Equity Securities
None.
Item 6.   SELECTED FINANCIAL DATA
Southern Company. See “SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA,” contained herein at pages II-103 and II-104.
Alabama Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-178 and II-179.
Georgia Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-258 and II-259.
Gulf Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-328 and II-329.
Mississippi Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-409 and II-410.
Southern Power. See “SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA,” contained herein at page II-458.
Item 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-11 through II-43.
Alabama Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-108 through II-132.
Georgia Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-183 through II-210.

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Gulf Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-263 through II-286.
Mississippi Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-333 through II-362.
Southern Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-414 through II-433.
Item 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of each of the registrants in Item 7 herein and Note 1 of each of the registrant’s financial statements under “Financial Instruments” in Item 8 herein. See also Note 10 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 9 to the financial statements of Gulf Power and Mississippi Power, and Note 8 to the financial statements of Southern Power in Item 8 herein.

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Item 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 2010 FINANCIAL STATEMENTS
         
    Page  
       
  II-9
  II-10
  II-44
  II-45
  II-46
  II-48
  II-50
  II-51
  II-52
 
       
       
  II-106
  II-107
  II-133
  II-134
  II-135
  II-137
  II-139
  II-140
  II-141
 
       
       
  II-181
  II-182
  II-211
  II-212
  II-213
  II-215
  II-216
  II-217
  II-218
 
       
       
  II-261
  II-262
  II-287
  II-288
  II-289
  II-291
  II-292
  II-293
  II-294

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    Page  
       
  II-331
  II-332
  II-363
  II-364
  II-365
  II-367
  II-368
  II-369
  II-370
 
       
       
  II-412
  II-413
  II-434
  II-435
  II-436
  II-438
  II-439
  II-440
Item 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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Item 9A.   CONTROLS AND PROCEDURES
Disclosure Controls And Procedures.
As of the end of the period covered by this annual report, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power conducted separate evaluations under the supervision and with the participation of each company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
Internal Control Over Financial Reporting.
     (a) Management’s Annual Report on Internal Control Over Financial Reporting.
Southern Company’s Management’s Report on Internal Control Over Financial Reporting is included on page II-9 of this Form 10-K.
Alabama Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-106 of this Form 10-K.
Georgia Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-181 of this Form 10-K.
Gulf Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-261 of this Form 10-K.
Mississippi Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-331 of this Form 10-K.
Southern Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-412 of this Form 10-K.
     (b) Attestation Report of the Registered Public Accounting Firm.
The report of Deloitte & Touche LLP, Southern Company’s independent registered public accounting firm, regarding Southern Company’s internal control over financial reporting is included on page II-10 of this Form 10-K.
Not applicable to Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power because these companies are not accelerated filers.
     (c) Changes in internal controls.
There have been no changes in Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the fourth quarter 2010 that have materially affected or are reasonably likely to materially affect Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.

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Item 9B.   OTHER INFORMATION
Southern Company
Southern Company, SCS, and Thomas A. Fanning entered into an amendment to Mr. Fanning’s Amended and Restated Change in Control Agreement, which terminates such agreement, effective February 22, 2011. Following the termination, Mr. Fanning is a participant in the Amended and Restated Senior Executive Change in Control Severance Plan. The Amendment is filed herewith as Exhibit 10(a)14.
Southern Company, SCS, and W. Paul Bowers entered into an amendment to Mr. Bowers’ Amended and Restated Change in Control Agreement, which terminates such agreement, effective February 22, 2011. Following the termination, Mr. Bowers is a participant in the Amended and Restated Senior Executive Change in Control Severance Plan. The amendment is filed herewith as Exhibit 10(a)18.
Southern Company, Alabama Power, and Charles D. McCrary entered into an amendment to Mr. McCrary’s Amended and Restated Change in Control Agreement, which terminates such agreement, effective February 22, 2011. Following the termination, Mr. McCrary is a participant in the Amended and Restated Senior Executive Change in Control Severance Plan. The amendment is filed herewith as Exhibit 10(a)8.
Effective February 23, 2011, The Southern Company Senior Executive Change in Control Severance Plan (Plan) was amended to reduce the severance benefit provided to all executive officers of Southern Company, except the Chief Executive Officer, from three times salary plus annual performance-based compensation target opportunity to two times that amount. The amendment also provides that any severance payment under the Plan shall not exceed three times a participant’s base amount as such term is defined under Section 280G of the Code. The amendment to the Plan is filed herewith as Exhibit 10(a)16.
On February 22, 2011, Georgia Power entered into a Separation and Release Agreement with Michael D. Garrett in connection with his retirement from Georgia Power. Under the agreement, Georgia Power will pay Mr. Garrett a severance payment of $1,000,000.00. The agreement contains standard non-compete and confidentiality terms and a legal release. The agreement is filed herewith as Exhibit 10(a)9.

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THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Southern Company and Subsidiary Companies 2010 Annual Report
Southern Company’s management is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management’s supervision, an evaluation of the design and effectiveness of Southern Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company’s internal control over financial reporting was effective as of December 31, 2010.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Southern Company’s financial statements, has issued an attestation report on the effectiveness of Southern Company’s internal control over financial reporting as of December 31, 2010. Deloitte & Touche LLP’s report on Southern Company’s internal control over financial reporting is included herein.
/s/ Thomas A. Fanning
Thomas A. Fanning
Chairman, President, and Chief Executive Officer
/s/ Art P. Beattie
Art P. Beattie
Executive Vice President and Chief Financial Officer
February 25, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Southern Company
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southern Company and Subsidiary Companies (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule of the Company listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and the financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting (page II-9). Our responsibility is to express an opinion on these financial statements and the financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements (pages II-44 to II-101) referred to above present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2011

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 2010 Annual Report
OVERVIEW
Business Activities
The primary business of Southern Company (the Company) is electricity sales in the Southeast by the traditional operating companies — Alabama Power, Georgia Power, Gulf Power, and Mississippi Power — and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market.
Many factors affect the opportunities, challenges, and risks of Southern Company’s electricity business. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. Each of the traditional operating companies has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future.
Another major factor is the profitability of the competitive market-based wholesale generating business and federal regulatory policy. Southern Power continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into power purchase agreements (PPAs) with investor owned utilities, independent power producers, municipalities, and electric cooperatives.
Southern Company’s other business activities include investments in leveraged lease projects, renewable energy projects, and telecommunications. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions and dispositions accordingly.
Key Performance Indicators
In striving to maximize shareholder value while providing cost-effective energy to more than four million customers, Southern Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share (EPS). Southern Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results.
Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The fossil/hydro 2010 Peak Season EFOR of 1.67% was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The performance for 2010 was better than the target for these reliability measures.
Southern Company’s 2010 results compared with its targets for some of these key indicators are reflected in the following chart:
                 
    2010 Target   2010 Actual
Key Performance Indicator   Performance   Performance
    Top quartile in    
Customer Satisfaction   customer surveys   Top quartile
Peak Season EFOR — fossil/hydro
  5.06% or less     1.67 %
Basic EPS
  $2.30 — $2.36   $ 2.37  
See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The performance achieved in 2010 reflects the continued emphasis that management places on these indicators as well as the commitment shown by employees in achieving or exceeding management’s expectations.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Earnings
Southern Company’s net income after dividends on preferred and preference stock of subsidiaries was $1.98 billion in 2010, an increase of $332 million from the prior year. This increase was primarily the result of increases in revenues due to colder weather in the first and fourth quarters 2010 and warmer weather in the second and third quarters 2010, a litigation settlement agreement with MC Asset Recovery, LLC (MC Asset Recovery) in the first quarter 2009, increased amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia Public Service Commission (PSC), revenues associated with increases in rates under Alabama Power’s rate stabilization and equalization plan (Rate RSE) and rate certificated new plant environmental (Rate CNP Environmental) that took effect in January 2010, and increases in sales primarily in the industrial sector. The 2010 increase was partially offset by increases in operations and maintenance expenses, which include an additional accrual to Alabama Power’s natural disaster reserve (NDR), a gain in 2009 on the early termination of two leveraged lease investments, and an increase in depreciation on additional plant in service related to environmental, distribution, and transmission projects. Net income after dividends on preferred and preference stock of subsidiaries was $1.64 billion in 2009 and $1.74 billion in 2008.
Basic EPS was $2.37 in 2010, $2.07 in 2009, and $2.26 in 2008. Diluted EPS, which factors in additional shares related to stock-based compensation, was $2.36 in 2010, $2.06 in 2009, and $2.25 in 2008. EPS for 2010 was negatively impacted by $0.12 per share as a result of an increase in the average shares outstanding.
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $1.8025 in 2010, $1.7325 in 2009, and $1.6625 in 2008. In January 2011, Southern Company declared a quarterly dividend of 45.50 cents per share. This is the 253rd consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. The Company targets a dividend payout ratio of approximately 70% of net income. For 2010, the actual payout ratio was 76%.
RESULTS OF OPERATIONS
Electricity Business
Southern Company’s electric utilities generate and sell electricity to retail and wholesale customers in the Southeast.
A condensed statement of income for the electricity business follows:
                                 
            Increase (Decrease)  
    Amount     from Prior Year  
    2010     2010     2009     2008  
    (in millions)  
Electric operating revenues
  $ 17,374     $ 1,732     $ (1,358 )   $ 1,860  
 
Fuel
    6,699       747       (865 )     973  
Purchased power
    563       89       (341 )     300  
Other operations and maintenance
    3,907       505       (183 )     111  
Depreciation and amortization
    1,494       19       62       199  
Taxes other than income taxes
    867       51       22       56  
 
Total electric operating expenses
    13,530       1,411       (1,305 )     1,639  
 
Operating income
    3,844       321       (53 )     221  
Other income (expense), net
    159       (41 )     53       26  
Interest expense, net of amounts capitalized
    833       (2 )     61       10  
Income taxes
    1,116       128       (49 )     87  
 
Net income
    2,054       154       (12 )     150  
Dividends on preferred and preference stock of subsidiaries
    65                   17  
 
Net income after dividends on preferred and preference stock of subsidiaries
  $ 1,989     $ 154     $ (12 )   $ 133  
 

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Electric Operating Revenues
Details of electric operating revenues were as follows:
                         
    Amount
    2010   2009   2008
    (in millions)
Retail — prior year
  $ 13,307     $ 14,055     $ 12,639  
Estimated change in —
                       
Rates and pricing
    384       144       668  
Sales growth (decline)
    32       (208 )      
Weather
    439       (21 )     (106 )
Fuel and other cost recovery
    629       (663 )     854  
 
Retail — current year
    14,791       13,307       14,055  
Wholesale revenues
    1,994       1,802       2,400  
Other electric operating revenues
    589       533       545  
 
Electric operating revenues
  $ 17,374     $ 15,642     $ 17,000  
 
Percent change
    11.1 %     (8.0 %)     12.3 %
 
Retail revenues increased $1.5 billion, decreased $748 million, and increased $1.4 billion in 2010, 2009, and 2008, respectively. The significant factors driving these changes are shown in the preceding table. The increase in rates and pricing in 2010 was primarily due to Rate RSE and Rate CNP Environmental increases at Alabama Power and the recovery of environmental costs at Gulf Power. The 2009 increase in rates and pricing when compared to the prior year was primarily due to an increase in revenues from customer charges at Alabama Power and increased environmental compliance cost recovery (ECCR) revenues at Georgia Power in accordance with its retail rate plan for the years 2008 through 2010 (2007 Retail Rate Plan), partially offset by a decrease in revenues from market-response rates to large commercial and industrial customers at Georgia Power. The 2008 increase in rates and pricing when compared to the prior year was primarily due to Alabama Power’s increase under its Rate RSE, as ordered by the Alabama PSC, and Georgia Power’s increase under the 2007 Retail Rate Plan, as ordered by the Georgia PSC. Also contributing to the 2008 increase was an increase in revenues from market-response rates to large commercial and industrial customers. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather.
Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power, and do not affect net income. The traditional operating companies may also have one or more regulatory mechanisms to recover other costs such as environmental, storm damage, new plants, and PPAs.
Wholesale revenues consist of PPAs with investor-owned utilities and electric cooperatives, unit power sales contracts, and short-term opportunity sales. Wholesale revenues from PPAs and unit power sales contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy revenues will vary depending on the market cost of available energy compared to the cost of the Company’s system-owned generation, demand for energy within the Company’s service territory, and the availability of the Company’s system generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy.
In 2010, wholesale revenues increased $192 million primarily due to higher capacity and energy revenues under existing PPAs and new PPAs at Southern Power that began in January, June, and July 2010, as well as increased energy sales that were not covered by PPAs at Southern Power due to more favorable weather. This increase was partially offset by the expiration of long-term unit power sales contracts in May 2010 at Alabama Power and the capacity subject to those contracts being made available for retail service starting in June 2010. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Alabama Power — Rate CNP” herein for additional information regarding the termination of certain unit power sales contracts in 2010.
In 2009, wholesale revenues decreased $598 million. Wholesale fuel revenues, which are generally offset by wholesale fuel expenses and do not affect net income, decreased $603 million in 2009. Excluding wholesale fuel revenues, wholesale revenues increased $5 million primarily due to additional revenues associated with a new PPA at Southern Power’s Plant Franklin Unit 3 which began in January 2009, partially offset by fewer short-term opportunity sales due to lower gas prices and reduced margins on short-term opportunity sales.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
In 2008, wholesale revenues increased $412 million primarily as a result of a 21.8% increase in the average cost of fuel per net kilowatt-hour (KWH) generated, as well as revenues resulting from new and existing PPAs and revenues derived from contracts for Southern Power’s Plant Oleander Unit 5 and Plant Franklin Unit 3 placed in operation in December 2007 and June 2008, respectively. The 2008 increase was partially offset by a decrease in short-term opportunity sales and weather-related generation load reductions.
Revenues associated with PPAs and opportunity sales were as follows:
                         
    2010     2009     2008  
    (in millions)  
Other power sales —
                       
Capacity and other
  $ 684     $ 575     $ 538  
Energy
    1,034       735       1,319  
 
Total
  $ 1,718     $ 1,310     $ 1,857  
 
KWH sales under unit power sales contracts decreased 55.0%, 7.5%, and 2.1% in 2010, 2009, and 2008, respectively. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Alabama Power – Rate CNP” herein for additional information regarding the termination of certain unit power sales contracts in 2010, which resulted in a decrease in capacity and energy revenues. In addition, fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales contracts, influence changes in energy sales. However, because the energy is generally sold at variable cost, fluctuations in energy sales have a minimal effect on earnings. The capacity and energy components of the unit power sales contracts were as follows:
                         
    2010   2009   2008
    (in millions)
Unit power sales —
                       
Capacity
  $ 136     $ 225     $ 223  
Energy
    140       267       320  
 
Total
  $ 276     $ 492     $ 543  
 
Other Electric Revenues
Other electric revenues increased $56 million, decreased $12 million, and increased $32 million in 2010, 2009, and 2008, respectively. Other electric revenues increased in 2010 primarily as a result of a $38 million increase in transmission revenues, a $4 million increase in rents from electric property, a $4 million increase in outdoor lighting revenues, and a $4 million increase in late fees. The 2009 decrease in other electric revenues was not material when compared to 2008. The 2008 increase in other electric revenues was not material when compared to 2007.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2010 and the percent change by year were as follows:
                                                         
    Total     Total KWH     Weather-Adjusted  
    KWHs     Percent Change     Percent Change  
    2010     2010     2009     2008     2010     2009     2008  
    (in billions)                                                       
Residential
    57.8       11.8 %     (1.1 )%     (2.0 )%     0.2 %     (0.7 )%     0.0 %
Commercial
    55.5       3.7       (1.7 )     (0.4 )     (0.6 )     (1.2 )     1.0  
Industrial
    50.0       7.7       (11.8 )     (3.7 )     7.1       (11.7 )     (3.5 )
Other
    0.9       (1.0 )     2.0       (2.9 )     (1.5 )     2.2       (2.7 )
     
Total retail
    164.2       7.6       (4.8 )     (2.1 )     2.0 %     (4.5 )%     (0.9 )%
     
Wholesale
    32.6       (2.8 )     (14.9 )     (3.4 )                        
 
Total energy sales
    196.8       5.7 %     (6.8 )%     (2.3 )%                        
 
Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales increased 11.6 billion KWHs in 2010. This increase was primarily the result of colder weather in the first and fourth quarters 2010 and warmer weather in the second and third quarters 2010, increased industrial KWH sales, and customer growth of 0.3%. Increased demand in the primary metals, chemicals, and transportations sectors were the main contributors to the increase in industrial KWH sales. Retail energy sales decreased 7.7 billion KWHs in 2009 primarily as a result of lower usage by industrial

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
customers due to the recessionary economy. Reduced demand in the primary metal, chemical, and textile sectors, as well as the stone, clay, and glass sector, contributed most significantly to the decrease in industrial KWH sales. Unfavorable weather also contributed to lower KWH sales across all customer classes. The number of customers in 2009 was flat compared to 2008. Retail energy sales in 2008 decreased 3.4 billion KWHs as a result of a 1.4% decrease in electricity usage mainly due to a slowing economy that worsened during the fourth quarter. The 2008 decrease in residential sales resulted primarily from lower home occupancy rates in Southern Company’s service area when compared to 2007. Throughout the year, reduced demand in the textile sector, the lumber sector, and the stone, clay, and glass sector contributed to the decrease in 2008 industrial sales. Additional weakness in the fourth quarter 2008 affected all major industrial segments. Significantly less favorable weather in 2008 when compared to 2007 also contributed to the 2008 decrease in retail energy sales. These decreases were partially offset by customer growth of 0.6%.
Wholesale energy sales decreased by 0.9 billion KWHs in 2010, decreased by 5.9 billion KWHs in 2009, and decreased by 1.4 billion KWHs in 2008. The decrease in wholesale energy sales in 2010 was primarily related to the expiration of long-term unit power sales contracts in May 2010 at Alabama Power and the capacity subject to those contracts being made available for retail service starting in June 2010. This decrease was partially offset by increased energy sales under existing PPAs and new PPAs at Southern Power that began in January, June, and July 2010, as well as sales that were not covered by PPAs at Southern Power primarily due to more favorable weather in 2010 compared to 2009. The decrease in wholesale energy sales in 2009 was primarily related to fewer short-term opportunity sales driven by lower gas prices and fewer uncontracted generating units at Southern Power available to sell electricity on the wholesale market. The decrease in wholesale energy sales in 2008 was primarily related to longer planned maintenance outages at a fossil unit in 2008 as compared to 2007 which reduced the availability of this unit for wholesale sales. Lower short-term opportunity sales primarily related to higher coal prices also contributed to the 2008 decrease. These decreases were partially offset by Plant Oleander Unit 5 and Plant Franklin Unit 3 at Southern Power being placed in operation in December 2007 and June 2008, respectively.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for the electric utilities. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market. Details of electricity generated and purchased by the electric utilities were as follows:
                         
    2010     2009     2008  
 
Total generation (billions of KWHs)
    196       187       198  
Total purchased power (billions of KWHs)
    10       8       11  
 
Sources of generation (percent)
                       
Coal
    58       57       68  
Nuclear
    15       16       15  
Gas
    25       23       16  
Hydro
    2       4       1  
 
Cost of fuel, generated (cents per net KWH)
                       
Coal
    3.93       3.70       3.27  
Nuclear
    0.63       0.55       0.50  
Gas
    4.27       4.58       7.58  
 
Average cost of fuel, generated (cents per net KWH)*
    3.50       3.38       3.52  
Average cost of purchased power (cents per net KWH)
    6.98       6.37       7.85  
 
 
*   Fuel includes fuel purchased by the electric utilities for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.
In 2010, fuel and purchased power expenses were $7.3 billion, an increase of $836 million or 13.0% above 2009 costs. This increase was primarily the result of a $538 million increase in the amount of total KWHs generated and purchased due primarily to increased customer demand. Also contributing to this increase was a $298 million increase in the average cost per KWH generated and purchased due primarily to a 3.6% increase in the cost per KWH generated and a 9.6% increase in the cost per KWH purchased.
In 2009, fuel and purchased power expenses were $6.4 billion, a decrease of $1.2 billion or 15.8% below 2008 costs. This decrease was primarily the result of an $839 million decrease related to the total KWHs generated and purchased due primarily to lower customer demand. Also contributing to this decrease was a $367 million reduction in the average cost of fuel and purchased power resulting primarily from a 39.6% decrease in the cost of gas per KWH generated.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
In 2008, fuel and purchased power expenses were $7.6 billion, an increase of $1.3 billion or 20.0% above 2007 costs. This increase was primarily the result of a $1.3 billion net increase in the average cost of fuel and purchased power partially resulting from a 25.3% increase in the cost of coal per net KWH generated and a 14.2% increase in the cost of gas per net KWH generated.
From an overall global market perspective, coal prices increased substantially in 2010 from the levels experienced in 2009, but remained lower than the unprecedented high levels of 2008. The slowly recovering U.S. economy and global demand from coal importing countries drove the higher prices in 2010, with concerns over regulatory actions, such as permitting issues, and their negative impact on production also contributing upward pressure. Domestic natural gas prices continued to be depressed by robust supplies, including production from shale gas, as well as lower demand. These lower natural gas prices contributed to increased use of natural gas-fueled generating units in 2009 and 2010. Uranium prices remained relatively constant during the early portion of 2010 but rose steadily during the second half of the year. At year end, uranium prices remained well below the highs set during 2007. Worldwide uranium production levels increased in 2010; however, secondary supplies and inventories were still required to meet worldwide reactor demand.
Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the traditional operating companies’ fuel cost recovery provisions. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” herein for additional information. Likewise, Southern Power’s PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses were $3.9 billion, $3.4 billion, and $3.6 billion, increasing $505 million, decreasing $183 million, and increasing $111 million in 2010, 2009, and 2008, respectively. Discussion of significant variances for components of other operations and maintenance expenses follows.
Other production expenses at fossil, hydro, and nuclear plants increased $277 million, decreased $70 million, and increased $63 million in 2010, 2009, and 2008, respectively. Production expenses fluctuate from year to year due to variations in outage schedules and changes in the cost of labor and materials. Other production expenses increased in 2010 mainly due to a $178 million increase in outage and maintenance costs and an $86 million increase in commodity and labor costs, reflecting a return to more normal spending levels when compared to 2009. Also contributing to this increase was an $18 million increase in maintenance costs related to additional equipment placed in service. Partially offsetting the 2010 increase was a $5 million loss recognized in 2009 on the transfer of Southern Power’s Plant Desoto. Other production expenses decreased in 2009 mainly due to a $104 million decrease related to less planned spending on outages and maintenance, as well as other cost containment activities, which were the results of efforts to offset the effects of the recessionary economy. The 2009 decrease was partially offset by a $6 million increase related to new facilities, a $5 million loss on the transfer of Southern Power’s Plant Desoto in 2009, a $6 million gain recognized in 2008 by Southern Power on the sale of an undeveloped tract of land to the Orlando Utilities Commission (OUC), and a $17 million increase in nuclear refueling costs. Other production expenses increased in 2008 primarily due to a $64 million increase related to expenses incurred for maintenance outages at generating units and a $30 million increase related to labor and materials expenses, partially offset by a $15 million decrease in nuclear refueling costs. The 2008 increase was also partially offset by a $24 million decrease related to new facilities, mainly lower costs associated with the 2007 write-off of Southern Power’s integrated coal gasification combined cycle (IGCC) project with the OUC. See Note 1 to the financial statements under “Property, Plant, and Equipment” for additional information regarding nuclear refueling costs.
Transmission and distribution expenses increased $143 million, decreased $41 million, and increased $4 million in 2010, 2009, and 2008, respectively. Transmission and distribution expenses fluctuate from year to year due to variations in maintenance schedules and normal changes in the cost of labor and materials. Transmission and distribution expenses increased in 2010 primarily due to increased spending on line clearing and other maintenance costs, reflecting a return to more normal spending levels, as well as an additional accrual to Alabama Power’s NDR. Transmission and distribution expenses decreased in 2009 primarily related to lower planned spending, as well as other cost containment activities, partially offset by an additional accrual to Alabama Power’s NDR. See FUTURE EARNINGS POTENTIAL — “PSC Matters – Alabama Power – Natural Disaster Reserve” herein for additional information. The 2008 increase in transmission and distribution expenses was not material when compared to the prior year.
Customer sales and service expenses increased $18 million, decreased $42 million, and increased $32 million in 2010, 2009, and 2008, respectively. Customer sales and service expenses increased in 2010 primarily as a result of an $8 million increase in sales expenses, a $13 million increase in customer service expense, a $10 million increase in records and collection, and a $3 million increase in uncollectible accounts expense. Partially offsetting this increase was a $7 million decrease in meter reading expenses and a $9 million decrease in other energy services. Customer sales and service expenses decreased in 2009 primarily as a result of a $12

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million decrease in customer service expenses, an $8 million decrease in meter reading expenses, a $10 million decrease in sales expenses, and a $7 million decrease in customer records related expenses. The 2008 increase in customer sales and service expenses was primarily a result of an increase in customer service expenses, including a $13 million increase in uncollectible accounts expense, a $9 million increase in meter reading expenses, and an $8 million increase for customer records and collections.
Administrative and general expenses increased $67 million, decreased $30 million, and increased $12 million in 2010, 2009, and 2008, respectively. Administrative and general expenses increased in 2010 primarily as a result of cost containment activities in 2009 which were taken to offset the effects of the recessionary economy. The 2008 increase in administrative and general expenses was not material when compared to 2007.
Depreciation and Amortization
Depreciation and amortization increased $19 million in 2010 primarily as the result of additional depreciation on plant in service related to environmental, transmission, and distribution projects, as well as additional depreciation at Southern Power. This increase was largely offset by a $133 million increase in the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC. See Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power– Retail Rate Plans” for additional information regarding Georgia Power’s cost of removal amortization.
Depreciation and amortization increased $62 million in 2009 primarily as a result of an increase in plant in service related to environmental, transmission, and distribution projects mainly at Alabama Power and Georgia Power and the completion of Southern Power’s Plant Franklin Unit 3, as well as an increase in depreciation rates at Southern Power. Partially offsetting the 2009 increase was a decrease associated with the amortization of the regulatory liability related to the cost of removal obligations as authorized by the Georgia PSC.
Depreciation and amortization increased $199 million in 2008 primarily as a result of an increase in plant in service related to environmental, transmission, and distribution projects mainly at Alabama Power and Georgia Power and generation projects at Georgia Power. An increase in depreciation rates at Georgia Power and Southern Power also contributed to the 2008 increase, as well as the expiration of a rate order previously allowing Georgia Power to levelize certain purchased power capacity costs and the completion of Southern Power’s Plant Oleander Unit 5 in December 2007 and Plant Franklin Unit 3 in June 2008.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $51 million in 2010 primarily due to higher municipal franchise fees at Georgia Power as a result of increased retail revenues, increases in state and municipal public utility license tax bases at Alabama Power, increases in gross receipts and franchise fees at Gulf Power, increases in ad valorem taxes, and increases in payroll taxes. Taxes other than income taxes increased $22 million in 2009 primarily as a result of increases in the bases of state and municipal public utility license taxes at Alabama Power and an increase in franchise fees at Gulf Power. Increases in franchise fees are associated with increases in revenues from energy sales. Taxes other than income taxes increased $56 million in 2008 primarily as a result of increases in franchise fees and municipal gross receipt taxes associated with increases in revenues from energy sales, as well as increases in property taxes associated with property tax actualizations and additional plant in service.
Other Income (Expense), Net
Other income (expense), net decreased $41 million in 2010 primarily due to a decrease in allowance for funds used during construction (AFUDC) equity, mainly due to the completion of environmental projects at Alabama Power and Gulf Power, and a $13 million profit recognized in 2009 at Southern Power related to a construction contract with the OUC. The 2010 decrease was partially offset by increases in AFUDC equity related to the increase in construction of three new combined cycle units and two new nuclear generating units at Georgia Power. Other income (expense), net increased $53 million in 2009 primarily due to an increase in AFUDC equity as a result of environmental projects at Alabama Power and Gulf Power and additional investments in transmission and distribution projects at Alabama Power. In addition, during 2009, Southern Power recognized a $13 million profit under a construction contract with the OUC whereby Southern Power provided engineering, procurement, and construction services to build a combined cycle unit. Other income (expense), net increased $26 million in 2008 primarily as a result of an increase in AFUDC equity related to additional investments in environmental equipment at generating plants at Alabama Power, Georgia Power, and Gulf Power, as well as additional investments in transmission and distribution projects mainly at Alabama Power and Georgia Power.

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Interest Expense, Net of Amounts Capitalized
Total interest charges and other financing costs decreased $2 million in 2010 primarily due to an $18 million decrease related to lower average interest rates on existing variable rate debt, an $11 million decrease in other interest costs, and a $2 million increase in capitalized interest as compared to 2009. The 2010 decrease was largely offset by a $29 million increase associated with $1.0 billion in additional debt outstanding at December 31, 2010 compared to December 31, 2009.
Total interest charges and other financing costs increased by $61 million in 2009 primarily as a result of a $100 million increase associated with $1.4 billion in additional debt outstanding at December 31, 2009 compared to December 31, 2008. Also contributing to the 2009 increase was $16 million in other interest costs. The 2009 increase was partially offset by $42 million related to lower average interest rates on existing variable rate debt and $13 million of additional capitalized interest as compared to 2008.
Total interest charges and other financing costs increased by $10 million in 2008 primarily as a result of a $65 million increase associated with $1.8 billion in additional debt outstanding at December 31, 2008 compared to December 31, 2007. Also contributing to the 2008 increase was $5 million in other interest costs. The 2008 increase was partially offset by $55 million related to lower average interest rates on existing variable rate debt and $7 million of additional capitalized interest as compared to 2007.
Income Taxes
Income taxes increased $128 million in 2010 primarily due to higher pre-tax earnings as compared to 2009, a decrease in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 production activities deduction, and an increase in Alabama state taxes due to a decrease in the state deduction for federal income taxes paid. Partially offsetting this increase were state tax credits at Georgia Power and tax benefits associated with the construction of a biomass facility at Southern Power. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.
Income taxes decreased $49 million in 2009 primarily due to lower pre-tax earnings as compared to 2008, an increase in AFUDC equity, which is not taxable, and an increase in the federal production activities deduction.
Income taxes increased $87 million in 2008 primarily due to higher pre-tax earnings as compared to 2007 and a 2007 deduction for a Georgia Power land donation. The 2008 increase was partially offset by an increase in AFUDC equity, which is not taxable.
Dividends on Preferred and Preference Stock of Subsidiaries
In both 2010 and 2009, dividends on preferred and preference stock of subsidiaries were flat compared to the applicable prior year.
Dividends on preferred and preference stock of subsidiaries increased $17 million in 2008 primarily as a result of issuances of $320 million and $150 million of preference stock in the third and fourth quarters of 2007, respectively, partially offset by the redemption of $125 million of preferred stock in January 2008.
Other Business Activities
Southern Company’s other business activities include the parent company (which does not allocate operating expenses to business units), investments in leveraged lease projects, and telecommunications. These businesses are classified in general categories and may comprise one or more of the following subsidiaries: Southern Company Holdings invests in various projects, including leveraged lease projects; and SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast.

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A condensed statement of income for Southern Company’s other business activities follows:
                                 
            Increase (Decrease)
    Amount   from Prior Year
    2010   2010   2009   2008
    (in millions)
Operating revenues
  $ 82     $ (19 )   $ (26 )   $ (86 )
 
Other operations and maintenance
    103       (22 )     (40 )     (44 )
MC Asset Recovery litigation settlement
          (202 )     202        
Depreciation and amortization
    19       (8 )     (2 )     (1 )
Taxes other than income taxes
    2             (1 )      
 
Total operating expenses
    124       (232 )     159       (45 )
 
Operating income (loss)
    (42 )     213       (185 )     (41 )
Equity in income (losses) of unconsolidated subsidiaries
    (2 )     (1 )     (11 )     35  
Leveraged lease income (losses)
    18       (22 )     125       (125 )
Other income (expense), net
    (16 )     (19 )     (8 )     (31 )
Interest expense
    62       (8 )     (22 )     (30 )
Income taxes
    (90 )     1       30       (7 )
 
Net income (loss)
  $ (14 )   $ 178     $ (87 )   $ (125 )
 
Operating Revenues
Southern Company’s non-electric operating revenues from these other businesses decreased $19 million in 2010 primarily as a result of a decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry. The $26 million decrease in 2009 primarily resulted from a $25 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry. The $86 million decrease in 2008 primarily resulted from a $60 million decrease associated with Southern Company terminating its investment in synthetic fuel projects at December 31, 2007 and a $21 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry. Also contributing to the 2008 decrease was a $5 million decrease in revenues from Southern Company’s energy-related services business.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses for these other businesses decreased $22 million in 2010 primarily as a result of lower administrative and general expenses for these other businesses. Other operations and maintenance expenses decreased $40 million in 2009 primarily as a result of a $15 million decrease in salary and wages, advertising, equipment, and network costs at SouthernLINC Wireless; a $10 million decrease in expenses associated with leveraged lease litigation costs; and a $6 million decrease in parent company expenses associated with the MC Asset Recovery litigation. Other operations and maintenance expenses decreased $44 million in 2008 primarily as a result of $11 million of lower coal expenses related to Southern Company terminating its investment in synthetic fuel projects at December 31, 2007; $9 million of lower sales expenses at SouthernLINC Wireless related to lower sales volume; and $5 million of lower parent company expenses related to advertising, litigation, and property insurance costs.
MC Asset Recovery Litigation Settlement
In March 2009, Southern Company entered into a litigation settlement agreement with MC Asset Recovery which resulted in a charge of $202 million and required MC Asset Recovery to release Southern Company and certain other designated avoidance actions assigned to MC Asset Recovery in connection with Mirant’s plan of reorganization, as well as to release all actions against current or former officers and directors of Mirant and Southern Company that had or could have been filed. Pursuant to the settlement, Southern Company recorded a charge in the first quarter 2009 of $202 million, which was paid in the second quarter 2009. The settlement has been completed and resolves all claims by MC Asset Recovery against Southern Company. In June 2009, the case was dismissed with prejudice.
Equity in Income (Losses) of Unconsolidated Subsidiaries
Equity in income (losses) of unconsolidated subsidiaries for 2010 was flat when compared to the prior year. Equity in income (losses) of unconsolidated subsidiaries decreased $11 million in 2009 as a result of an $11 million gain recognized in 2008 related to the

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dissolution of a partnership that was associated with synthetic fuel production facilities. Equity in income (losses) of unconsolidated subsidiaries increased $35 million in 2008 primarily as a result of Southern Company terminating its investment in synthetic fuel projects at December 31, 2007.
Leveraged Lease Income (Losses)
Southern Company has several leveraged lease agreements which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Leveraged lease income (losses) decreased $22 million in 2010 primarily as a result of a $26 million gain recorded in 2009 associated with the early termination of two international leveraged lease investments, the proceeds from which were required to extinguish all debt related to the leveraged lease investments, and a portion of which had make-whole redemption provisions. This resulted in a $17 million loss in 2009, partially offsetting the gain. In addition, leveraged lease income decreased $6 million in 2010 primarily due to lease income no longer being recognized on the terminated leveraged lease investments. Leveraged lease income (losses) increased $125 million in 2009 primarily as a result of the application in 2008 of certain accounting standards related to leveraged leases, as well as a $26 million gain recorded in the second quarter 2009 associated with the early termination of two international leveraged lease investments. The proceeds from the termination were required to be used to extinguish all debt related to leveraged lease investments, a portion of which had make-whole redemption provisions. This resulted in a $17 million loss and partially offset the 2009 increase. Leveraged lease income (losses) decreased $125 million in 2008 as a result of Southern Company’s decision to participate in a settlement with the Internal Revenue Service (IRS) related to deductions for several sale-in-lease-out transactions and the resulting application of certain accounting standards related to leveraged leases.
Other Income (Expense), Net
Other income (expense), net for these other businesses decreased $19 million in 2010 primarily due to charitable contributions made by the parent company. The 2009 change in other income (expense), net when compared to the prior year was not material. Other income (expense), net decreased $31 million in 2008 primarily as a result of the 2007 gain on a derivative transaction in the synthetic fuel business which settled on December 31, 2007.
Interest Expense
Total interest charges and other financing costs for these other businesses decreased $8 million in 2010 primarily due to lower average interest rates on existing variable rate debt. Total interest charges and other financing costs decreased $22 million in 2009 primarily as a result of $26 million associated with lower average interest rates on existing variable rate debt and a $2 million decrease attributed to other interest charges. The 2009 decrease was partially offset by a $4 million increase associated with $63 million in additional debt outstanding at December 31, 2009 compared to December 31, 2008. Total interest charges and other financing costs decreased $30 million in 2008 primarily as a result of $29 million associated with lower average interest rates on existing variable rate debt and a $4 million decrease attributed to lower interest rates associated with new debt issued to replace maturing securities. At December 31, 2008, these other businesses had $92 million in additional debt outstanding compared to December 31, 2007. The 2008 decrease was partially offset by a $5 million increase in other interest costs.
Income Taxes
The 2010 increase in income taxes for these other businesses was not material when compared to the prior year. Income taxes increased $30 million in 2009 excluding the effects of the $202 million charge resulting from the litigation settlement with MC Asset Recovery in the first quarter 2009. The 2009 increase was primarily due to the application in 2008 of certain accounting standards related to leveraged leases and income taxes. Partially offsetting this increase was lower tax expense associated with the early termination of two international leveraged lease investments and the extinguishment of the associated debt discussed previously under “Leveraged Lease Income (Losses).” Income taxes decreased $7 million in 2008 primarily as a result of leveraged lease losses discussed previously under “Leveraged Lease Income (Losses),” partially offset by a $36 million decrease in net synthetic fuel tax credits as a result of Southern Company terminating its investment in synthetic fuel projects at December 31, 2007. See Note 5 to the financial statements under “Effective Tax Rate” for further information.
Effects of Inflation
The traditional operating companies are subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing

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power. Southern Power is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on Southern Company’s results of operations has not been substantial in recent years.
FUTURE EARNINGS POTENTIAL
General
The four traditional operating companies operate as vertically integrated utilities providing electricity to customers within their service areas in the Southeastern U.S. Prices for electricity provided to retail customers are set by state PSCs under cost-based regulatory principles. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the Federal Energy Regulatory Commission (FERC). Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Southern Power continues to focus on long-term capacity contracts, optimized by limited energy trading activities. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about regulatory matters.
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’s primary business of selling electricity. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Other major factors include profitability of the competitive wholesale supply business and federal regulatory policy. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service area. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available in the Southeast, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Changes in economic conditions impact sales for the traditional operating companies and Southern Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings.
In 2010, Southern Company system generating capacity increased 30 megawatts due to the completion of a solar photovoltaic plant near Cimarron, New Mexico. In general, Southern Company has constructed or acquired new generating capacity only after entering into long-term capacity contracts for the new facilities or to meet requirements of Southern Company’s regulated retail markets, both of which are optimized by limited energy trading activities. See FUTURE EARNINGS POTENTIAL — “Construction Program” herein and Note 7 to the financial statements for additional information.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including facilities

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co-owned by Mississippi Power and Gulf Power. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened. The separate action against Alabama Power is ongoing.
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. On September 2, 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including the claim relating to a facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims.
Southern Company believes that the traditional operating companies complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time.
Carbon Dioxide Litigation
New York Case
In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On December 6, 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. The ultimate outcome of these matters cannot be determined at this time.
Kivalina Case
In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth

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Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. The ultimate outcome of this matter cannot be determined at this time.
Other Litigation
Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded.
Environmental Statutes and Regulations
General
The electric utilities’ operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2010, the electric utilities had invested approximately $8.1 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of $500 million, $1.3 billion, and $1.6 billion for 2010, 2009, and 2008, respectively. The Company expects that capital expenditures to comply with existing statutes and regulations will be $341 million, $427 million, and $452 million for 2011, 2012, and 2013, respectively. These environmental costs that are known and estimable at this time are included under the heading “Capital” in the table under FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” herein. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $74 million to $289 million in 2011, $191 million to $670 million in 2012, and $476 million to $1.9 billion in 2013. The Company’s compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of any new or revised environmental statutes and regulations that are enacted, including the proposed environmental legislation and regulations described below; the cost, availability, and existing inventory of emissions allowances; and the fuel mix of the electric utilities.
Compliance with any new federal or state legislation or regulations relating to global climate change, air quality, coal combustion byproducts, including coal ash, water quality, or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the electric utilities’ operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the electric utilities’ commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for Southern Company. Through 2010, the electric utilities had spent approximately $7 billion in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. As a result, emissions control projects have been completed recently or are underway. Additional controls are currently planned or under consideration to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements.
The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone air quality standard. A 20-county area within metropolitan Atlanta is the only location within Southern Company’s service area that is currently designated as

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nonattainment for the current standard. On November 30, 2010, the EPA extended the attainment date for this area by one year as a result of improving air quality. In March 2008, the EPA issued a final rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the level of the standard. Under the EPA’s current schedule, a final revision to the eight-hour ozone standard is expected in July 2011, with state implementation plans for any resulting nonattainment areas due in mid-2014. The revised eight-hour ozone standard is expected to result in designation of new nonattainment areas within Southern Company’s service territory, and could result in additional required reductions in NOx emissions.
During 2005, the EPA’s annual fine particulate matter nonattainment designations became effective for several areas within Southern Company’s service area in Alabama and Georgia. State implementation plans demonstrating attainment with the annual standard for all areas have been submitted to the EPA. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour average fine particulate matter air quality standard. In October 2009, the EPA designated the Birmingham area as nonattainment for the 24-hour standard. In April 2010, the State of Alabama requested that the EPA re-designate Birmingham to attainment for the 24-hour standard based on current air quality data. In September 2010, the EPA determined that Birmingham has air quality data that meets the 24-hour standard. The EPA is expected to propose new annual and 24-hour fine particulate matter standards during the summer of 2011.
Final revisions to the National Ambient Air Quality Standard for SO2, including the establishment of a new one-hour standard, became effective on August 23, 2010. Since the EPA intends to rely on computer modeling for implementation of the SO2 standard, the identification of potential nonattainment areas remains uncertain and could ultimately include areas within the Company’s service territory. Implementation of the revised SO2 standard could result in additional required reductions in SO2 emissions and increased compliance and operation costs.
Revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO2), which established a new one-hour standard, became effective on April 12, 2010. Although none of the areas within Southern Company’s service territory are expected to be designated as nonattainment for the NO2 standard, based on current ambient air quality monitoring data, the new NO2 standard could result in significant additional compliance and operational costs for units that require new source permitting.
Twenty-eight eastern states, including each of the states within Southern Company’s service area, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place while the EPA develops a revised rule. States in the Southern Company service territory have completed plans to implement CAIR, and emissions reductions are being accomplished by the installation and operation of emissions controls at coal-fired facilities of the electric utilities and/or by the purchase of emissions allowances.
On August 2, 2010, the EPA published a proposed rule, referred to as the Transport Rule, to replace CAIR. This proposed rule would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO2 and NOx that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, Florida, and Georgia, to reduce annual emissions of SO2 and NOx from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including each of the states in Southern Company’s service territory, to achieve additional reductions in NOx emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requested comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA stated that it also intends to develop a second phase of the Transport Rule in 2011 to address the more stringent ozone air quality standards after they are finalized. The EPA expects to finalize the Transport Rule in June 2011 and require compliance beginning in 2012.
The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO2 and NOx, and no additional controls beyond CAIR are anticipated to be necessary at any of the traditional operating companies’ facilities. States have completed or are currently completing implementation plans for BART compliance and other measures required to achieve the first phase of reasonable progress.

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The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal- and oil-fired electric generating units which will establish emission limitations for numerous hazardous air pollutants, including mercury. As part of a proceeding in the U.S. District Court for the District of Columbia, the EPA has entered into a consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011 and a final rule by November 16, 2011.
On April 29, 2010, the EPA issued a proposed Industrial Boiler (IB) MACT rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers and start-up boilers. The EPA issued the final rules on February 23, 2011 and, at the same time, issued a notice of intent to reconsider the final rules to allow for additional public review and comment. The impact of these regulations will depend on their final form and the outcome of any legal challenges and cannot be determined at this time.
The impacts of the eight-hour ozone, fine particulate matter, SO2 and NO2 standards, the proposed Transport Rule, the Clean Air Visibility Rule, and the proposed MACT rules for electric generating units and industrial boilers on the Company cannot be determined at this time and will depend on the specific provisions of the final rules, resolution of any pending and future legal challenges, and the development and implementation of rules at the state level. However, these additional regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.
The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company has already installed a number of SO2 and NOx emissions controls to ensure continued compliance with applicable air quality requirements.
In addition to the federal air quality laws described above, Georgia Power also is subject to the requirements of the State of Georgia’s Multi-Pollutant Rule, which was adopted in 2007. The Multi-Pollutant Rule is designed to reduce emissions of mercury, SO2, and NOx state-wide by requiring the installation of specified control technologies at certain coal-fired generating units by specific dates between December 31, 2008 and June 1, 2015. The State of Georgia also adopted a companion rule that requires a 95% reduction in SO2 emissions from the controlled units on the same or similar timetable. Through December 31, 2010, Georgia Power had installed the required controls on 10 of its largest coal-fired generating units and is in the process of installing the required controls on six additional units. As a result of uncertainties related to the potential federal air quality regulations described above, Georgia Power has suspended certain work related to both the installation of emissions control equipment at Plant Branch Units 1 and 2 and Plant Yates Units 6 and 7 and the conversion of Plant Mitchell from coal-fired to biomass-fired. Georgia Power continues to analyze the potential costs and benefits of installing the required controls on its remaining coal-fired generating units in light of the potential federal regulations described above. Georgia Power may determine that retiring and replacing certain of these existing units with new generating resources or purchased power is more economically efficient than installing the required environmental controls.
Georgia Power currently expects to file an update to its integrated resource plan in June 2011. Under the terms of an Alternate Rate Plan approved by the Georgia PSC for Georgia Power which became effective January 1, 2011 and will continue through December 31, 2013 (the 2010 ARP), any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets (resulting from new or revised environmental regulations) through 2013 that are approved by the Georgia PSC in connection with an updated IRP will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. Such costs that may be deferred as a regulatory asset include any impairment losses that may result from a decision to retire certain units that are no longer cost effective in light of new or modified environmental regulations. In addition, in connection with the 2010 ARP, the Georgia PSC also approved revised depreciation rates that will recover the remaining book value of certain of Georgia Power’s existing coal-fired units by December 31, 2014.
The ultimate outcome of these matters cannot be determined at this time.
Water Quality
In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to the U.S. Supreme Court. In April 2009, the U.S. Supreme Court held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing intake structures. The EPA is expected to propose revisions to the regulations in March 2011 and issue final regulations in mid-2012. While the U.S. Supreme Court’s decision

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may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on the specific provisions of the EPA’s final rule and on the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time. However, if the final rules require the installation of cooling towers at certain existing facilities of the traditional operating companies, the traditional operating companies may be subject to significant additional compliance costs and capital expenditures that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates.
In December 2009, the EPA announced its determination that revision of the current effluent guidelines for steam electric power plants is warranted, and the EPA has announced its intention to adopt such revisions by January 2014. New wastewater treatment requirements are expected and may result in the installation of additional controls on certain Southern Company system facilities. The impact of revised guidelines will depend on the studies conducted in connection with the rulemaking, as well as the specific requirements of the final rule, and, therefore, cannot be determined at this time.
Environmental Remediation
Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the traditional operating companies could incur substantial costs to clean up properties. The traditional operating companies conduct studies to determine the extent of any required cleanup and have recognized in their respective financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional operating companies may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters — Environmental Remediation” for additional information.
Coal Combustion Byproducts
The traditional operating companies currently operate 22 electric generating plants with on-site coal combustion byproduct storage facilities (some with both “wet” (ash ponds) and “dry” (landfill) storage facilities). In addition to on-site storage, the traditional operating companies also sell a portion of their coal combustion byproducts to third parties for beneficial reuse (approximately one-fourth in recent years). Historically, individual states have regulated coal combustion byproducts and the states in Southern Company’s service territory each have their own regulatory parameters. Each traditional operating company has a routine and robust inspection program in place to ensure the integrity of its coal ash surface impoundments and compliance with applicable regulations.
The EPA is currently evaluating whether additional regulation of coal combustion byproducts (including coal ash and gypsum) is merited under federal solid and hazardous waste laws. On June 21, 2010, the EPA published a proposed rule that requested comments on two potential regulatory options for the management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of, or significant change to, existing storage facilities and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options.
On November 19, 2010, Southern Company filed publicly available comments with the EPA regarding the rulemaking proposal. These comments included a preliminary cost analysis under various alternatives in the rulemaking proposal. Southern Company regards these estimates as pre-screening figures that should be distinguished from the more formalized cost estimates Southern Company provides for projects that are more definite as to the elements and timing of execution. Although its analysis was preliminary, Southern Company concluded that potential compliance costs under the proposed rules would be substantially higher than the estimates reflected in the EPA’s rulemaking proposal.
The ultimate financial and operational impact of any new regulations relating to coal combustion byproducts cannot be determined at this time and will be dependent upon numerous factors. These factors include: whether coal combustion byproducts will be regulated as hazardous waste or non-hazardous waste; whether the EPA will require early closure of existing wet storage facilities; whether beneficial reuse will be limited or eliminated through a hazardous waste designation; whether the construction of lined landfills is required; whether hazardous waste landfill permitting will be required for on-site storage; whether additional waste water treatment will be required; the extent of any additional groundwater monitoring requirements; whether any equipment modifications will be required; the extent of any changes to site safety practices under a hazardous waste designation; and the time period over which compliance will be required. There can be no assurance as to the timing of adoption or the ultimate form of any such rules.

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While the ultimate outcome of this matter cannot be determined at this time, and will depend on the final form of any rules adopted and the outcome of any legal challenges, additional regulation of coal combustion byproducts could have a material impact on the generation, management, beneficial use, and disposal of such byproducts. Any material changes are likely to result in substantial additional compliance, operational, and capital costs that could affect future unit retirement and replacement decisions. Moreover, the traditional operating companies could incur additional material asset retirement obligations with respect to closing existing storage facilities. Southern Company’s results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.
Global Climate Issues
Although the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, with the goal of mandating renewable energy standards and reductions in greenhouse gas emissions, neither this legislation nor similar measures passed the U.S. Senate before the end of the 2010 session. Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and/or energy efficiency standards are expected to continue to be considered in Congress.
The financial and operational impacts of climate or energy legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal, natural gas, and biomass prices and cost recovery through regulated rates.
While climate legislation has yet to be adopted, the EPA is moving forward with regulation of greenhouse gases under the Clean Air Act. In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. In December 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has taken the position that when this rule became effective on January 2, 2011, carbon dioxide and other greenhouse gases became regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants and other commercial and industrial facilities. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, known as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, which began on January 2, 2011, applies to sources and projects that would already be covered under PSD or Title V, whereas the second phase will begin on July 1, 2011 and applies to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. In addition to these rules, the EPA has entered into a proposed settlement agreement to issue standards of performance for greenhouse gas emissions from new and modified fossil fuel-fired electric generating units and greenhouse gas emissions guidelines for existing sources. Under the proposed settlement agreement, the EPA commits to issue the proposed standards by July 2011 and the final standards by May 2012.
All of the EPA’s final Clean Air Act rulemakings have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit; however, the court declined motions to stay the rules pending resolution of those challenges. As a result, the rules may impact the amount of time it takes to obtain PSD permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate outcome of these rules cannot be determined at this time and will depend on the content of the final rules and the outcome of any legal challenges.
International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. The December 2009 negotiations resulted in a nonbinding agreement that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The most recent round of negotiations took place in December 2010. The outcome and impact of the international negotiations cannot be determined at this time.
Although the outcome of federal, state, and international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. These costs could affect

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future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units. See Item 1 – BUSINESS – “Rate Matters – Integrated Resource Planning” for additional information. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.
In 2009, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the electric utilities were approximately 121 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2010 is approximately 131 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units.
The Company is actively evaluating and developing electric generating technologies with lower greenhouse gas emissions. These include, but are not limited to, new nuclear generation, including two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4) in Georgia; construction of the Kemper IGCC in Mississippi with 65% carbon capture; and renewables investments, including the construction of a biomass plant in Sacul, Texas. In addition, a subsidiary of the Company completed construction on a solar photovoltaic plant near Cimarron, New Mexico in 2010. The Company is currently considering additional projects and is pursuing research into the costs and viability of other renewable technologies.
PSC Matters
Alabama Power
Rate RSE
Alabama Power operates under Rate RSE approved by the Alabama PSC. Alabama Power’s Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. Retail rates remain unchanged when the retail return on common equity (ROE) is projected to be between 13.0% and 14.5%. If Alabama Power’s actual retail return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail ROE fall below the allowed equity return range.
The Rate RSE increase for 2010 was 3.24%, or $152 million annually, and was effective in January 2010. In December 2010, Alabama Power made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2011 and earnings were within the specified return range. Consequently, the retail rates will remain unchanged in 2011 under Rate RSE. Under the terms of Rate RSE, the maximum increase for 2012 cannot exceed 5.00%.
Rate CNP
Alabama Power’s retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated PPAs under a Rate CNP. There was no adjustment to the Rate CNP to recover certificated PPA costs in 2008 or 2009. Effective April 2010, Rate CNP was reduced by approximately $70 million annually, primarily due to the expiration on May 31, 2010 of the PPA with Southern Power covering the capacity of Plant Harris Unit 1. It is estimated that there will be a slight decrease to the current Rate CNP effective April 2011.
Rate CNP also allows for the recovery of Alabama Power’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Retail rates increased approximately 2.4% in January 2008 and 4.3% in January 2010 due to environmental costs. In October 2008, Alabama Power agreed to defer collection of any increase in rates under this portion of Rate CNP, which permits recovery of costs associated with environmental laws and regulations, from 2009 until 2010. The deferral of the retail rate adjustments had an immaterial impact on annual cash flows, and had no significant effect on the Company’s revenues or net income. On December 1, 2010, Alabama Power submitted calculations associated with its cost of complying with environmental mandates, as provided under Rate CNP Environmental. The filing reflects an incremental increase in the revenue requirement associated with such environmental compliance, which would be recoverable in the billing months of January 2011 through December 2011. In order to afford additional rate stability to customers as the economy continues to recover from the recession, the Alabama PSC ordered on January 4, 2011 that Alabama Power leave in effect for 2011 the factors associated with Alabama Power’s

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environmental compliance costs for the year 2010. Any recoverable amounts associated with 2011 will be reflected in the 2012 filing. The ultimate outcome of this matter cannot be determined at this time.
Natural Disaster Reserve
Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Natural Disaster Rate (Rate NDR) charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Alabama Power has discretionary authority to accrue certain additional amounts as circumstances warrant.
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows Alabama Power to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the reserve.
For the year ended December 31, 2010, Alabama Power accrued an additional $48 million to the NDR, resulting in an accumulated balance of approximately $127 million. For the year ended December 31, 2009, Alabama Power accrued an additional $40 million to the NDR, resulting in an accumulated balance of approximately $75 million. These accruals are included in the balance sheets under other regulatory liabilities, deferred and are reflected as operations and maintenance expense in the statements of income.
Nuclear Outage Accounting Order
On August 17, 2010, the Alabama PSC approved a change to the nuclear maintenance outage accounting process associated with routine refueling activities. Previously, Alabama Power accrued nuclear outage operations and maintenance expenses for the two units of Plant Farley during the 18-month cycle for the outages. In accordance with the new order, nuclear outage expenses will be deferred when the charges actually occur and then amortized over the subsequent 18-month period.
The initial result of implementation of the new accounting order is that no nuclear maintenance outage expenses will be recognized from January 2011 through December 2011, which will decrease nuclear outage operations and maintenance expenses in 2011 from 2010 by approximately $50 million. During the fall of 2011, actual nuclear outage expenses associated with one unit of Plant Farley will be deferred to a regulatory asset account; beginning in January 2012, these deferred costs will be amortized to nuclear operations and maintenance expenses over an 18-month period. During the spring of 2012, actual nuclear outage expenses associated with the other unit of Plant Farley will be deferred to a regulatory asset account; beginning in July 2012, these deferred costs will be amortized to nuclear operations and maintenance expenses over an 18-month period. Alabama Power will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a subsequent 18-month period.
Georgia Power
The economic recession significantly reduced Georgia Power’s revenues upon which retail rates were set by the Georgia PSC for 2008 through 2010 (2007 Retail Rate Plan). In June 2009, despite stringent efforts to reduce expenses, Georgia Power’s projected retail ROE for both 2009 and 2010 was below 10.25%. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, in June 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations.
In August 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, Georgia Power could amortize up to $108 million of the regulatory liability in 2009 and up to $216 million in 2010, limited to the amount needed to earn no

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more than a 9.75% and 10.15% retail ROE in 2009 and 2010, respectively. For the years ended December 31, 2009 and 2010, Georgia Power amortized $41 million and $174 million of the regulatory liability, respectively.
On December 21, 2010, the Georgia PSC approved the 2010 ARP. The terms of the 2010 ARP reflect a settlement agreement among Georgia Power, the Georgia PSC’s Public Interest Advocacy Staff, and eight other intervenors. Under the terms of the 2010 ARP, Georgia Power will amortize approximately $92 million of its remaining regulatory liability related to other cost of removal obligations over the three years ending December 31, 2013.
Also under the terms of the 2010 ARP, effective January 1, 2011, Georgia Power increased its (1) traditional base tariff rates by approximately $347 million; (2) Demand-Side Management (DSM) tariff rates by approximately $31 million; (3) ECCR tariff rate by approximately $168 million; and (4) Municipal Franchise Fee (MFF) tariff rate by approximately $16 million, for a total increase in base revenues of approximately $562 million.
Under the 2010 ARP, the following additional base rate adjustments will be made to Georgia Power’s tariffs in 2012 and 2013:
  Effective January 1, 2012, the DSM tariffs will increase by $17 million;
 
  Effective April 1, 2012, the traditional base tariffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Units 4 and 5 for the period from commercial operation through December 31, 2013;
 
  Effective January 1, 2013, the DSM tariffs will increase by $18 million;
 
  Effective January 1, 2013, the traditional base tariffs will increase to recover the revenue requirements for the lesser of actual capital costs incurred or the amounts certified by the Georgia PSC for Plant McDonough Unit 6 for the period from commercial operation through December 31, 2013; and
 
  The MFF tariff will increase consistent with these adjustments.
Georgia Power currently estimates these adjustments will result in annualized base revenue increases of approximately $190 million in 2012 and $93 million in 2013.
Under the 2010 ARP, Georgia Power’s retail ROE is set at 11.15% and earnings will be evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. If at any time during the term of the 2010 ARP, Georgia Power projects that retail earnings will be below 10.25% for any calendar year, it may petition the Georgia PSC for the implementation of an Interim Cost Recovery (ICR) tariff to adjust Georgia Power’s earnings back to a 10.25% retail ROE. The Georgia PSC will have 90 days to rule on any such request. If approved, any ICR tariff would expire at the earlier of January 1, 2014 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR, Georgia Power may file a full rate case.
Except as provided above, Georgia Power will not file for a general base rate increase while the 2010 ARP is in effect. Georgia Power is required to file a general rate case by July 1, 2013, in response to which the Georgia PSC would be expected to determine whether the 2010 ARP should be continued, modified, or discontinued.
Fuel Cost Recovery
The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. In previous years, the traditional operating companies experienced higher than expected fuel costs for coal, natural gas, and uranium. These higher fuel costs have resulted in total under recovered fuel costs included in the balance sheets of Alabama Power, Georgia Power, and Gulf Power of approximately $420 million at December 31, 2010. As of December 31, 2010, Mississippi Power had a total over recovered fuel balance of $55 million. At December 31, 2009, total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf Power were approximately $667 million and Alabama Power and Mississippi Power had a total over recovered fuel balance of approximately $229 million. The traditional operating companies continuously monitor the under or over recovered fuel cost balances.

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Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changing the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Retail Regulatory Matters – Alabama Power – Fuel Cost Recovery” and “Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery” for additional information.
Legislation
Stimulus Funding
On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the U.S. Department of Energy (DOE), formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding, to be matched by Southern Company, will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. The ultimate outcome of this matter cannot be determined at this time.
Healthcare Reform
On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Southern Company and the traditional operating companies have been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under generally accepted accounting principles (GAAP), any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of Southern Company. Southern Company continues to assess the extent to which the legislation and associated regulations may affect its future healthcare and related employee benefit plan costs. Any future impact on the financial statements of Southern Company cannot be determined at this time. See Note 5 to the financial statements under “Current and Deferred Income Taxes” for additional information.
Income Tax Matters
Georgia State Income Tax Credits
Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue (DOR) has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. The Georgia DOR has appealed to the Georgia Court of Appeals and a decision is expected later this year. Any decision may be subject to further appeal to the Georgia Supreme Court. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on Southern Company’s net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers in accordance with the 2010 ARP. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s cash flow. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot now be determined.
Tax Method of Accounting for Repairs
Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. On a consolidated basis, the new tax method resulted in net positive cash flow in 2010 of approximately $297 million. Although Internal Revenue Service (IRS) approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing

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final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. The ultimate outcome of this matter cannot be determined at this time.
Bonus Depreciation
On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which could have a significant impact on the future cash flows of Southern Company. The application of the bonus depreciation provisions in these acts in 2010 provided approximately $393 million in increased cash flow. Southern Company estimates the potential increased cash flow for 2011 to be between approximately $500 million and $600 million.
Internal Revenue Code Section 199 Domestic Production Deduction
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code of 1986, as amended. The deduction is equal to a stated percentage of qualified production activities net income. The percentage was phased in over the years 2005 through 2010. For 2008 and 2009, a 6% reduction was available to Southern Company. Thereafter, the allowed rate is 9%; however, due to increased tax deductions from bonus depreciation and pension contributions, there was no domestic production deduction available to Southern Company for 2010, and none is projected to be available for 2011. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.
Construction Program
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Southern Company intends to continue its strategy of developing and constructing new generating facilities, including natural gas and biomass units at Southern Power, natural gas and new nuclear units at Georgia Power, and the Kemper IGCC at Mississippi Power, as well as adding environmental control equipment and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approvals in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See Note 7 to the financial statements under “Construction Program” for estimated construction expenditures for the next three years. In addition, see Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power – Nuclear Construction,” “Retail Regulatory Matters – Georgia Power – Other Construction,” and “Retail Regulatory Matters – Mississippi Power Integrated Coal Gasification Combined Cycle” for additional information.
On September 3, 2010, Georgia Power filed with the Georgia PSC the Nuclear Construction Cost Recovery (NCCR) tariff, as authorized in April 2009 under the Georgia Nuclear Energy Financing Act. The Georgia PSC has ordered Georgia Power to report against the total certified cost of Plant Vogtle Units 3 and 4 of approximately $6.1 billion. In addition, on December 21, 2010, the Georgia PSC approved Georgia Power’s NCCR tariff. The NCCR tariff became effective January 1, 2011 and is expected to collect approximately $223 million during 2011 to recover financing costs associated with the construction of Plant Vogtle Units 3 and 4.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials,

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and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements. See Note 3 to the financial statements for information regarding material issues.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Southern Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company’s Board of Directors.
Electric Utility Regulation
Southern Company’s traditional operating companies, which comprised approximately 95% of Southern Company’s total operating revenues for 2010, are subject to retail regulation by their respective state PSCs and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional operating companies are permitted to charge customers based on allowable costs. As a result, the traditional operating companies apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional operating companies; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.
Contingent Obligations
Southern Company and its subsidiaries are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject them to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company periodically evaluates its exposure to such risks and, in accordance with GAAP, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect Southern Company’s financial statements.

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These events or conditions include the following:
  Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, coal combustion byproducts, including coal ash, control of toxic substances, hazardous and solid wastes, and other environmental matters.
 
  Changes in existing income tax regulations or changes in IRS or state revenue department interpretations of existing regulations.
 
  Identification of additional sites that require environmental remediation or the filing of other complaints in which Southern Company or its subsidiaries may be asserted to be a potentially responsible party.
 
  Identification and evaluation of other potential lawsuits or complaints in which Southern Company or its subsidiaries may be named as a defendant.
 
  Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, state revenue departments, the FERC, or the EPA.
Unbilled Revenues
Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, and power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.
Alabama Power is better able to determine unbilled KWH sales due to the installation of automated meters. At the end of each month, amounts of electricity delivered are read for the customers with automated meters. From this reading, unbilled KWH sales are determined and included in Alabama Power’s unbilled revenue calculation. For customers without automated meter readings, amounts of unbilled electricity delivered are estimated.
Pension and Other Postretirement Benefits
Southern Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining Southern Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on Southern Company’s investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company’s target asset allocation. Southern Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments.

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The following table illustrates the sensitivity to changes in Southern Company’s long-term assumptions with respect to the expected long-term rate of return on plan assets and the assumed discount rate:
             
            Increase/(Decrease) in
        Increase/(Decrease) in   Projected Obligation for
    Increase/(Decrease) in   Projected Obligation for   Other Postretirement
    Total Benefit Expense   Pension Plan   Benefit Plans
Change in Assumption   for 2011   at December 31, 2010   at December 31, 2010
    (in millions)
25 basis point change in discount rate
  $25/$(17)   $249/$(236)   $52/$(50)
25 basis point change in salary assumption
  $13/$(12)   $63/$(60)   N/M
25 basis point change in long-term return on plan assets
  $20/$(20)   N/M   N/M
 
N/M – Not meaningful
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Company’s financial condition remained stable at December 31, 2010. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.
Southern Company’s investments in the qualified pension plan and the nuclear decommissioning trust funds remained stable in value as of December 31, 2010. In December 2010, the traditional operating companies and certain other subsidiaries contributed $620 million to the qualified pension plan. Southern Company does not expect any material changes to funding obligations to the nuclear decommissioning trust funds prior to 2014.
Net cash provided from operating activities in 2010 totaled $4 billion, an increase of $728 million from the corresponding period in 2009. Significant changes in operating cash flow for 2010 as compared to the corresponding period in 2009 include an increase in net income, a reduction in fossil fuel stock, and an increase in deferred income taxes primarily due to the change in the tax accounting method for repair costs. A contribution to the qualified pension plan partially offset these increases. Net cash provided from operating activities in 2009 totaled $3.3 billion, a decrease of $201 million from the corresponding period in 2008. Significant changes in operating cash flow for 2009 as compared to the corresponding period in 2008 include a reduction to net income, increased levels of coal inventory, and increased cash outflows for tax payments. These uses of funds were partially offset by increased cash inflows as a result of higher fuel cost recovery rates included in customer billings. Net cash provided from operating activities in 2008 totaled $3.5 billion, an increase of $30 million as compared to 2007. Significant changes in operating cash flow for 2008 included a $264 million increase in the use of funds for fossil fuel inventory as compared to the corresponding period in 2007. This use of funds was offset by an increase in cash of $312 million in accrued taxes primarily due to a difference between the periods in payments for federal taxes and property taxes.
Net cash used for investing activities in 2010 totaled $4.3 billion primarily due to property additions to utility plant. Net cash used for investing activities in 2009 totaled $4.3 billion primarily due to property additions to utility plant of $4.7 billion, partially offset by approximately $340 million in cash received from the early termination of two leveraged lease investments. Net cash used for investing activities in 2008 totaled $4.1 billion primarily due to property additions to utility plant of $4.0 billion.
Net cash provided from financing activities totaled $22 million in 2010, a decrease of $1.3 billion from the corresponding period in 2009. This decrease was primarily due to redemptions of long-term debt in 2010. Net cash provided from financing activities totaled $1.3 billion in 2009 primarily due to the issuances of new long-term debt and common stock, partially offset by cash outflows for repayments of long-term debt and dividend payments. Net cash provided from financing activities totaled $878 million in 2008 primarily due to long-term debt issuances.
Significant balance sheet changes in 2010 include an increase of $2.8 billion in total property, plant, and equipment for the installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Other

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significant changes include an increase in notes payable of $658 million used primarily for construction expenditures and general corporate purposes and $1.3 billion of additional equity.
At the end of 2010, the closing price of Southern Company’s common stock was $38.23 per share, compared with book value of $19.21 per share. The market-to-book value ratio was 199% at the end of 2010, compared with 184% at year-end 2009.
Sources of Capital
Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of the Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2011, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities.
Except as described below with respect to potential DOE loan guarantees, the traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors.
On June 18, 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs, or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the combined construction and operating license for Plant Vogtle Units 3 and 4 from the Nuclear Regulatory Commission (NRC), negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.
In addition, Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE but has yet to begin discussions with the DOE regarding the terms and conditions of any loan guarantee. There can be no assurance that the DOE will issue federal loan guarantees for Mississippi Power.
The issuance of securities by the traditional operating companies is generally subject to the approval of the applicable state PSC. The issuance of all securities by Mississippi Power and Southern Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company and certain of its subsidiaries file registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts, if any, registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
Southern Company, each traditional operating company, and Southern Power obtain financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company.
Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs (which are backed by bank credit facilities).
At December 31, 2010, Southern Company and its subsidiaries had approximately $447.4 million of cash and cash equivalents and $4.8 billion of unused credit arrangements with banks, of which $1.6 billion expire in 2011 and $3.2 billion expire in 2012. Approximately $81 million of the credit facilities expiring in 2011 allow for the execution of term loans for an additional two-year period, and $927 million allow for the execution of one-year term loans. Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of the individual company. Southern Company and its subsidiaries are currently in compliance with all such covenants. A portion of the unused credit with banks is

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allocated to provide liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds requiring liquidity support as of December 31, 2010 was approximately $1.3 billion. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The traditional operating companies may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of each of the traditional operating companies. At December 31, 2010, the Southern Company system had approximately $1.3 billion of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During 2010, Southern Company had an average of $690 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $1.3 billion. At December 31, 2009, the Southern Company system had approximately $638 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During 2009, Southern Company had an average of $956 million of commercial paper outstanding at a weighted average interest rate of 0.4% per annum and the maximum amount outstanding for commercial paper was $1.4 billion. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Financing Activities
During 2010, Southern Company issued $400 million aggregate principal amount of Series 2010A 2.375% Senior Notes due September 15, 2015. The net proceeds were used to redeem $250 million aggregate principal amount of Southern Company Capital Funding, Inc.’s Series C 5.75% Senior Notes due November 15, 2015. In addition, certain Southern Company subsidiaries issued $2.8 billion of senior notes and other long-term debt and entered into bank term loan agreements of $125 million. The proceeds were used to repay maturing long-term and short-term indebtedness and for other general corporate purposes, including the applicable subsidiary’s continuous construction program. Southern Company also issued 19.6 million shares of common stock for $629 million through the Southern Investment Plan and employee and director stock plans. In addition, Southern Company issued 4.1 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of $143 million, net of $1 million in fees and commissions. The proceeds from the sale of the common stock were used by the Company for general corporate purposes, including the investment by the Company in its subsidiaries, and to repay a portion of its outstanding short-term indebtedness.
In December 2010, Mississippi Power incurred obligations in connection with the issuance of $100 million of revenue bonds in two series, each of which is due December 1, 2040. The first series of $50 million was issued with an initial fixed rate of 2.25% through January 14, 2013 and the second series of $50 million was issued with a floating rate. The proceeds from the first series bonds were used to finance the acquisition and construction of buildings and immovable equipment in connection with Mississippi Power’s construction of the Kemper IGCC. Proceeds from the second series bonds were classified as restricted cash at December 31, 2010 and these bonds were redeemed on February 8, 2011.
Subsequent to December 31, 2010, Alabama Power entered into forward-starting interest rate swaps to mitigate exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $200 million.
Also subsequent to December 31, 2010, Georgia Power issued $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds were used to repay a portion of Georgia Power’s outstanding short-term indebtedness and for general corporate purposes, including Georgia Power’s continuous construction program.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Off-Balance Sheet Financing Arrangements
In 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel for approximately $370 million. In 2003, the generating facility was acquired by Juniper Capital L.P. (Juniper), a limited partnership whose investors are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50% of Juniper’s assets. Mississippi Power is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The lease also provides for a residual value guarantee, approximately 73% of the acquisition cost, by Mississippi Power that is due upon termination of the lease in the event that Mississippi Power does not renew the lease or purchase the assets and that the fair market value is less than the unamortized cost of the assets. In April 2010, Mississippi Power was required to notify the lessor, Juniper, if it intended to terminate the lease at the end

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of the initial term expiring in October 2011. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the Plant Daniel combined cycle generating units for approximately $354 million or renew the lease for approximately $31 million annually for 10 years. Mississippi Power will have to provide notice of its intent to either renew the lease or purchase the facility by July 2011. The ultimate outcome of this matter cannot be determined at this time. See Note 7 to the financial statements under “Operating Leases” for additional information.
Credit Rating Risk
Southern Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At December 31, 2010, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $489 million. At December 31, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.5 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.
On August 12, 2010, Moody’s Investors Service (Moody’s) downgraded the issuer and long-term debt ratings of Southern Company (senior unsecured to Baa1 from A3); Moody’s also announced that it had downgraded the short-term ratings of Southern Company and a financing subsidiary of Southern Company that issues commercial paper for the benefit of several Southern Company subsidiaries (including Georgia Power, Gulf Power, and Mississippi Power) to P-2 from P-1. In addition, Moody’s downgraded the issuer and long-term debt ratings of Georgia Power (senior unsecured to A3 from A2), Gulf Power (senior unsecured to A3 from A2), and Mississippi Power (senior unsecured to A2 from A1). All of these companies have stable ratings outlooks from Moody’s.
On September 3, 2010, Fitch Ratings, Inc. (Fitch) confirmed the long-term debt ratings of Southern Company (senior unsecured A), but announced that the ratings outlook of Southern Company had been revised to negative, and that the issuer default ratings and long-term debt ratings of Mississippi Power had been downgraded by one notch (senior unsecured to A+ from AA- and issuer default rating to A from A+). On December 22, 2010, Fitch announced that the ratings outlook of Southern Company and Georgia Power had been revised from negative to stable.
Market Price Risk
Southern Company is exposed to market risks, primarily commodity price risk and interest rate risk. The Company may also occasionally have limited exposure to foreign currency exchange rates. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to a change in interest rates, Southern Company and certain of its subsidiaries enter into derivatives that have been designated as hedges. Derivatives outstanding at December 31, 2010 have a notional amount of $650 million and are related to fixed and floating rate obligations over the next several years. The weighted average interest rate on $2.5 billion of long-term variable interest rate exposure that has not been hedged at January 1, 2011 was 0.75%. If Southern Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $25 million at January 1, 2011. For further information, see Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements.
Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional operating companies continue to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
for natural gas purchases. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the years ended December 31 were as follows:
                 
    2010   2009
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (178 )   $ (285 )
Contracts realized or settled
    197       367  
Current period changes(a)
    (215 )     (260 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (196 )   $ (178 )
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The change in the fair value positions of the energy-related derivative contracts for the year ended December 31, 2010 was a decrease of $18 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and the price of natural gas. At December 31, 2010, Southern Company had a net hedge volume of 149 million mmBtu with a weighted average contract cost approximately $1.35 per mmBtu above market prices, compared to 145 million mmBtu at December 31, 2009 with a weighted average contract cost approximately $1.23 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the traditional operating companies’ fuel cost recovery clauses.
At December 31, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as assets (liabilities) were as follows:
                 
Asset (Liability) Derivatives   2010   2009
    (in millions)
Regulatory hedges
  $ (193 )   $ (175 )
Cash flow hedges
    (1 )     (2 )
Not designated
    (2 )     (1 )
 
Total fair value
  $ (196 )   $ (178 )
 
Energy-related derivative contracts which are designated as regulatory hedges relate to the traditional operating companies’ fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives that are designated as cash flow hedges are mainly used by Southern Power to hedge anticipated purchases and sales and are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Total net unrealized pre-tax gains (losses) recognized in the statements of income for the years ended December 31, 2010, 2009, and 2008 for energy-related derivative contracts that are not hedges were $(2) million, $(5) million, and $1 million, respectively.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 10 to the financial statements for further discussion of fair value measurement. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2010 were as follows:
                                 
    December 31, 2010
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (196 )     (144 )     (52 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (196 )   $ (144 )   $ (52 )   $  
 
Southern Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. Southern Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s, a division of The McGraw Hill Companies, Inc., or with counterparties who have posted collateral to cover potential credit exposure. Therefore, Southern Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by the Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.
Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international and the creditworthiness of the lessees, including a review of the value of the underlying leased assets and the credit ratings of the lessees. Southern Company’s domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in the Company’s international lease transactions are also required to provide additional collateral in the event of a credit downgrade below a certain level.
Capital Requirements and Contractual Obligations
The construction programs of the Company’s subsidiaries are currently estimated to include a base level investment of $4.9 billion, $5.1 billion, and $4.5 billion for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $341 million, $427 million, and $452 million for 2011, 2012, and 2013, respectively. In addition, the Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $74 million to $289 million for 2011, $191 million to $670 million for 2012, and $476 million to $1.9 billion for 2013. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power – Nuclear Construction,” “Retail Regulatory Matters – Georgia Power – Other Construction,” and “Retail Regulatory Matters –Mississippi Power Integrated Coal Gasification Combined Cycle” and Note 7 to the financial statements under “Construction Program” for additional information.
As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.”

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
In addition, as discussed in Note 2 to the financial statements, Southern Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the traditional operating companies’ respective regulatory commissions.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 6, 7, and 11 to the financial statements for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Contractual Obligations
                                                 
            2012-   2014-   After   Uncertain    
    2011   2013   2015   2015   Timing(d)   Total
    (in millions)
Long-term debt(a)
                                               
Principal
  $ 1,278     $ 2,938     $ 1,138     $ 14,029     $     $ 19,383  
Interest
    876       1,610       1,369       11,194             15,049  
Preferred and preference stock dividends(b)
    65       130       130                   325  
Energy-related derivative obligations(c)
    151       55                         206  
Operating leases
    154       170       94       103             521  
Capital leases
    23       28       13       35             99  
Unrecognized tax benefits and interest(d)
    203                         122       325  
Purchase commitments(e)
                                               
Capital(f)
    4,554       9,242                         13,796  
Limestone(g)
    39       82       72       89             282  
Coal
    3,810       3,244       1,656       1,798             10,508  
Nuclear fuel
    335       427       349       807             1,918  
Natural gas(h)
    1,357       2,280       1,687       3,413             8,737  
Biomass fuel(i)
          32       36       110             178  
Purchased power
    260       506       559       2,439             3,764  
Long-term service agreements(j)
    110       270       290       1,435             2,105  
Trusts —
                                               
Nuclear decommissioning(k)
    3       4       4       35             46  
Pension and other postretirement benefit plans(l)
    64       147                         211  
 
Total
  $ 13,282     $ 21,165     $ 7,397     $ 35,487     $ 122     $ 77,453  
 
(a)   All amounts are reflected based on final maturity dates. Southern Company and its subsidiaries plan to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2011, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).
 
(b)   Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only.
 
(c)   For additional information, see Notes 1 and 11 to the financial statements.
 
(d)   The timing related to the realization of $122 million in unrecognized tax benefits and corresponding interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. See Notes 3 and 5 to the financial statements for additional information.
 
(e)   Southern Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2010, 2009, and 2008 were $4.0 billion, $3.5 billion, and $3.8 billion, respectively.
 
(f)   Southern Company provides forecasted capital expenditures for a three-year period. Amounts represent current estimates of total expenditures, excluding those amounts related to contractual purchase commitments for nuclear fuel. In addition, such amounts exclude Southern Company’s estimates of potential incremental investments to comply with anticipated new environmental regulations which could range from $74 million to $289 million for 2011, $191 million to $670 million for 2012, and $476 million to $1.9 billion for 2013. At December 31, 2010, significant purchase commitments were outstanding in connection with the construction program.
 
(g)   As part of Southern Company’s program to reduce SO2 emissions from its coal plants, the traditional operating companies have entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment.
 
(h)   Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2010.
 
(i)   Biomass fuel commitments are based on minimum committed tonnage of wood waste purchases.
 
(j)   Long-term service agreements include price escalation based on inflation indices.
 
(k)   Projections of nuclear decommissioning trust fund contributions are based on the 2010 ARP for Georgia Power.
 
(l)   Southern Company forecasts contributions to the qualified pension and other postretirement benefit plans over a three-year period. Southern Company does not expect to be required to make any contributions to the qualified pension plan during the next three years. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from Southern Company’s corporate assets.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
Southern Company’s 2010 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the wholesale business, retail sales, customer growth, economic recovery, fuel cost recovery and other rate actions, environmental regulations and expenditures, future earnings, dividend payout ratios, access to sources of capital, projections for the qualified pension plan, postretirement benefit, and nuclear decommissioning trust fund contributions, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impact of the American Recovery and Reinvestment Act of 2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 2010, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
  the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
 
  current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS audits;
 
  the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;
 
  variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures;
 
  available sources and costs of fuels;
 
  effects of inflation;
 
  ability to control costs and avoid cost overruns during the development and construction of facilities;
 
  investment performance of Southern Company’s employee benefit plans and nuclear decommissioning trust funds;
 
  advances in technology;
 
  state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
 
  regulatory approvals and actions related to the Plant Vogtle expansion, including Georgia PSC and NRC approvals and potential DOE loan guarantees;
 
  regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC approvals and potential DOE loan guarantees;
 
  the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
 
  internal restructuring or other restructuring options that may be pursued;
 
  potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
 
  the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
 
  the ability to obtain new short- and long-term contracts with wholesale customers;
 
  the direct or indirect effect on Southern Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
 
  interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company’s and its subsidiaries’ credit ratings;
 
  the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices;
 
  catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as influenzas, or other similar occurrences;
 
  the direct or indirect effects on Southern Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
 
  the effect of accounting pronouncements issued periodically by standard setting bodies; and
 
  other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
Southern Company expressly disclaims any obligation to update any forward-looking statements.

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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2010, 2009, and 2008
Southern Company and Subsidiary Companies 2010 Annual Report
                         
 
    2010     2009     2008  
    (in millions)          
 
                       
Operating Revenues:
                       
Retail revenues
  $ 14,791     $ 13,307     $ 14,055  
Wholesale revenues
    1,994       1,802       2,400  
Other electric revenues
    589       533       545  
Other revenues
    82       101       127  
 
Total operating revenues
    17,456       15,743       17,127  
 
Operating Expenses:
                       
Fuel
    6,699       5,952       6,818  
Purchased power
    563       474       815  
Other operations and maintenance
    4,010       3,526       3,748  
MC Asset Recovery litigation settlement
          202        
Depreciation and amortization
    1,513       1,503       1,443  
Taxes other than income taxes
    869       818       797  
 
Total operating expenses
    13,654       12,475       13,621  
 
Operating Income
    3,802       3,268       3,506  
Other Income and (Expense):
                       
Allowance for equity funds used during construction
    194       200       152  
Interest income
    24       23       33  
Leveraged lease income (losses)
    18       31       (85 )
Gain on disposition of lease termination
          26        
Loss on extinguishment of debt
          (17 )      
Interest expense, net of amounts capitalized
    (895 )     (905 )     (866 )
Other income (expense), net
    (77 )     (22 )     (18 )
 
Total other income and (expense)
    (736 )     (664 )     (784 )
 
Earnings Before Income Taxes
    3,066       2,604       2,722  
Income taxes
    1,026       896       915  
 
Consolidated Net Income
    2,040       1,708       1,807  
Dividends on Preferred and Preference Stock of Subsidiaries
    65       65       65  
 
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries
  $ 1,975     $ 1,643     $ 1,742  
 
Common Stock Data:
                       
Earnings per share (EPS)—
                       
Basic EPS
  $ 2.37     $ 2.07     $ 2.26  
Diluted EPS
    2.36       2.06       2.25  
 
Average number of shares of common stock outstanding — (in millions)
                       
Basic
    832       795       771  
Diluted
    837       796       775  
 
Cash dividends paid per share of common stock
  $ 1.8025     $ 1.7325     $ 1.6625  
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2010, 2009, and 2008
Southern Company and Subsidiary Companies 2010 Annual Report
                         
 
    2010     2009     2008  
    (in millions)          
Operating Activities:
                       
Consolidated net income
  $ 2,040     $ 1,708     $ 1,807  
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
                       
Depreciation and amortization, total
    1,831       1,788       1,704  
Deferred income taxes
    1,038       25       215  
Deferred revenues
    (103 )     (54 )     120  
Allowance for equity funds used during construction
    (194 )     (200 )     (152 )
Leveraged lease (income) losses
    (18 )     (31 )     85  
Gain on disposition of lease termination
          (26 )      
Loss on extinguishment of debt
          17        
Pension, postretirement, and other employee benefits
    (614 )     (3 )     21  
Stock based compensation expense
    33       23       20  
Hedge settlements
    2       (19 )     15  
Generation construction screening costs
    (51 )     (22 )      
Other, net
    86       102       (108 )
Changes in certain current assets and liabilities —
                       
-Receivables
    80       585       (176 )
-Fossil fuel stock
    135       (432 )     (303 )
-Materials and supplies
    (30 )     (39 )     (23 )
-Other current assets
    (17 )     (47 )     (36 )
-Accounts payable
    4       (125 )     (74 )
-Accrued taxes
    (308 )     (95 )     293  
-Accrued compensation
    180       (226 )     36  
-Other current liabilities
    (103 )     334       20  
 
Net cash provided from operating activities
    3,991       3,263       3,464  
 
Investing Activities:
                       
Property additions
    (4,086 )     (4,670 )     (3,961 )
Investment in restricted cash from revenue bonds
    (50 )     (55 )     (96 )
Distribution of restricted cash from revenue bonds
    25       119       69  
Nuclear decommissioning trust fund purchases
    (2,009 )     (1,234 )     (720 )
Nuclear decommissioning trust fund sales
    2,004       1,228       712  
Proceeds from property sales
    18       340       34  
Cost of removal, net of salvage
    (125 )     (119 )     (123 )
Change in construction payables
    (51 )     215       83  
Other investing activities
    18       (143 )     (124 )
 
Net cash used for investing activities
    (4,256 )     (4,319 )     (4,126 )
 
Financing Activities:
                       
Increase (decrease) in notes payable, net
    659       (306 )     (314 )
Proceeds —
                       
Long-term debt issuances
    3,151       3,042       3,687  
Common stock issuances
    772       1,286       474  
Redemptions —
                       
Long-term debt
    (2,966 )     (1,234 )     (1,469 )
Redeemable preferred stock
                (125 )
Payment of common stock dividends
    (1,496 )     (1,369 )     (1,280 )
Payment of dividends on preferred and preference stock of subsidiaries
    (65 )     (65 )     (66 )
Other financing activities
    (33 )     (25 )     (29 )
 
Net cash provided from financing activities
    22       1,329       878  
 
Net Change in Cash and Cash Equivalents
    (243 )     273       216  
Cash and Cash Equivalents at Beginning of Year
    690       417       201  
 
Cash and Cash Equivalents at End of Year
  $ 447     $ 690     $ 417  
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED BALANCE SHEETS
At December 31, 2010 and 2009
Southern Company and Subsidiary Companies 2010 Annual Report
                 
 
Assets   2010     2009  
    (in millions)  
Current Assets:
               
Cash and cash equivalents
  $ 447     $ 690  
Restricted cash and cash equivalents
    68       43  
Receivables —
               
Customer accounts receivable
    1,140       953  
Unbilled revenues
    420       394  
Under recovered regulatory clause revenues
    209       333  
Other accounts and notes receivable
    285       375  
Accumulated provision for uncollectible accounts
    (25 )     (25 )
Fossil fuel stock, at average cost
    1,308       1,447  
Materials and supplies, at average cost
    827       794  
Vacation pay
    151       145  
Prepaid expenses
    784       508  
Other regulatory assets, current
    210       167  
Other current assets
    59       49  
 
Total current assets
    5,883       5,873  
 
Property, Plant, and Equipment:
               
In service
    56,731       53,588  
Less accumulated depreciation
    20,174       19,121  
 
Plant in service, net of depreciation
    36,557       34,467  
Nuclear fuel, at amortized cost
    670       593  
Construction work in progress
    4,775       4,170  
 
Total property, plant, and equipment
    42,002       39,230  
 
Other Property and Investments:
               
Nuclear decommissioning trusts, at fair value
    1,370       1,070  
Leveraged leases
    624       610  
Miscellaneous property and investments
    277       283  
 
Total other property and investments
    2,271       1,963  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    1,280       1,047  
Prepaid pension costs
    88        
Unamortized debt issuance expense
    178       208  
Unamortized loss on reacquired debt
    274       255  
Deferred under recovered regulatory clause revenues
    218       373  
Other regulatory assets, deferred
    2,402       2,702  
Other deferred charges and assets
    436       395  
 
Total deferred charges and other assets
    4,876       4,980  
 
Total Assets
  $ 55,032     $ 52,046  
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED BALANCE SHEETS
At December 31, 2010 and 2009
Southern Company and Subsidiary Companies 2010 Annual Report
                 
 
Liabilities and Stockholders’ Equity   2010     2009  
    (in millions)  
Current Liabilities:
               
Securities due within one year
  $ 1,301     $ 1,113  
Notes payable
    1,297       639  
Accounts payable
    1,275       1,329  
Customer deposits
    332       331  
Accrued taxes —
               
Accrued income taxes
    8       13  
Unrecognized tax benefits
    187       166  
Other accrued taxes
    440       398  
Accrued interest
    225       218  
Accrued vacation pay
    194       184  
Accrued compensation
    438       248  
Liabilities from risk management activities
    152       125  
Other regulatory liabilities, current
    88       528  
Other current liabilities
    535       292  
 
Total current liabilities
    6,472       5,584  
 
Long-Term Debt (See accompanying statements)
    18,154       18,131  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    7,554       6,455  
Deferred credits related to income taxes
    235       248  
Accumulated deferred investment tax credits
    509       448  
Employee benefit obligations
    1,580       2,304  
Asset retirement obligations
    1,257       1,201  
Other cost of removal obligations
    1,158       1,091  
Other regulatory liabilities, deferred
    312       278  
Other deferred credits and liabilities
    517       346  
 
Total deferred credits and other liabilities
    13,122       12,371  
 
Total Liabilities
    37,748       36,086  
 
Redeemable Preferred Stock of Subsidiaries (See accompanying statements)
    375       375  
 
Total Stockholders’ Equity (See accompanying statements)
    16,909       15,585  
 
Total Liabilities and Stockholders’ Equity
  $ 55,032     $ 52,046  
 
Commitments and Contingent Matters (See notes)
               
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2010 and 2009
Southern Company and Subsidiary Companies 2010 Annual Report
                                     
 
        2010     2009     2010     2009  
        (in millions)     (percent of total)  
 
                                   
Long-Term Debt:
                                   
Long-term debt payable to affiliated trusts —
                                   
Maturity
  Interest Rates                                
2044
  5.88%   $ 206     $ 206                  
Variable rate (3.39% at 1/1/11) due 2042
      206       206                  
 
Total long-term debt payable to affiliated trusts
        412       412                  
 
Long-term senior notes and debt —
                                   
Maturity
  Interest Rates                                
2010
  4.70%           102                  
2011
  4.00% to 5.57%     304       304                  
2012
  4.85% to 6.25%     1,778       1,778                  
2013
  1.30% to 6.00%     1,436       936                  
2014
  4.15% to 4.90%     425       425                  
2015
  2.38% to 5.75%     1,184       1,025                  
2016 through 2048
  2.25% to 8.20%     9,438       8,822                  
Adjustable rates (at 1/1/11):
                                   
2010
  0.35% to 0.97%           990                  
2011
  0.56% to 0.78%     915       790                  
2013
  0.62%     350                        
2040
  0.44%     50                        
 
Total long-term senior notes and debt
        15,880       15,172                  
 
Other long-term debt —
                                   
Pollution control revenue bonds —
                                   
Maturity
  Interest Rates                                
2016 through 2049
  0.80% to 6.00%     1,807       1,973                  
Variable rates (at 1/1/11):
                                   
2011 through 2041
  0.26% to 0.51%     1,284       1,612                  
 
Total other long-term debt
        3,091       3,585                  
 
Capitalized lease obligations
        99       98                  
 
Unamortized debt (discount), net
        (27 )     (23 )                
 
Total long-term debt (annual interest requirement — $876 million)
        19,455       19,244                  
Less amount due within one year
        1,301       1,113                  
 
Long-term debt excluding amount due within one year
        18,154       18,131       51.2 %     53.2 %
 

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2010 and 2009
Southern Company and Subsidiary Companies 2010 Annual Report
                                 
 
    2010     2009     2010     2009  
    (in millions)     (percent of total)  
 
                                   
Redeemable Preferred Stock of Subsidiaries:
                               
Cumulative preferred stock
                               
$100 par or stated value — 4.20% to 5.44%
                               
Authorized — 20 million shares
                               
Outstanding — 1 million shares
    81       81                  
$1 par value — 5.20% to 5.83%
                               
Authorized — 28 million shares
                               
Outstanding — 12 million shares: $25 stated value
    294       294                  
 
Total redeemable preferred stock of subsidiaries
(annual dividend requirement — $20 million)
    375       375       1.1       1.1  
 
Common Stockholders’ Equity:
                               
Common stock, par value $5 per share —
    4,219       4,101                  
Authorized — 1 billion shares
                               
Issued — 2010: 844 million shares
                               
— 2009: 820 million shares
                               
Treasury — 2010: 0.5 million shares
                               
— 2009: 0.5 million shares
                               
Paid-in capital
    3,702       2,995                  
Treasury, at cost
    (15 )     (15 )                
Retained earnings
    8,366       7,885                  
Accumulated other comprehensive income (loss)
    (70 )     (88 )                
 
Total common stockholders’ equity
    16,202       14,878       45.7       43.6  
 
Preferred and Preference Stock of Subsidiaries:
                               
Non-cumulative preferred stock
                               
$25 par value — 6.00% to 6.13%
                               
Authorized — 60 million shares
                               
Outstanding — 2 million shares
    45       45                  
Preference stock
                               
Authorized — 65 million shares
                               
Outstanding — $1 par value — 5.63% to 6.50%
    343       343                  
— 14 million shares (non-cumulative)
                               
— $100 par or stated value — 6.00% to 6.50%
    319       319                  
— 3 million shares (non-cumulative)
                               
 
Total preferred and preference stock of subsidiaries
(annual dividend requirement — $45 million)
    707       707       2.0       2.1  
 
Total stockholders’ equity
    16,909       15,585                  
 
Total Capitalization
  $ 35,438     $ 34,091       100.0 %     100.0 %
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2010, 2009, and 2008
Southern Company and Subsidiary Companies 2010 Annual Report
                                                                         
                                                    Accumulated   Preferred    
                                                    Other   and    
    Number of   Common Stock           Comprehensive   Preference    
    Common Shares   Par   Paid-In           Retained   Income   Stock of    
    Issued   Treasury   Value   Capital   Treasury   Earnings   (Loss)   Subsidiaries   Total
    (in thousands)   (in millions)
Balance at December 31, 2007
    763,503       (399 )   $ 3,817     $ 1,454     $ (11 )   $ 7,155     $ (30 )   $ 707     $ 13,092  
Net income after dividends on preferred and preference stock of subsidiaries
                                  1,742                   1,742  
Other comprehensive loss
                                        (75 )           (75 )
Stock issued
    14,113             71       402                               473  
Stock-based compensation
                      36                               36  
Cash dividends
                                  (1,279 )                 (1,279 )
Other
          (25 )           1       (1 )     (6 )                 (6 )
 
Balance at December 31, 2008
    777,616       (424 )     3,888       1,893       (12 )     7,612       (105 )     707       13,983  
Net income after dividends on preferred and preference stock of subsidiaries
                                  1,643                   1,643  
Other comprehensive income
                                        17             17  
Stock issued
    42,536             213       1,074                               1,287  
Stock-based compensation
                      26                               26  
Cash dividends
                                  (1,369 )                 (1,369 )
Other
          (81 )           2       (3 )     (1 )                 (2 )
 
Balance at December 31, 2009
    820,152       (505 )     4,101       2,995       (15 )     7,885       (88 )     707       15,585  
Net income after dividends on preferred and preference stock of subsidiaries
                                  1,975                   1,975  
Other comprehensive income
                                        18             18  
Stock issued
    23,662             118       654                               772  
Stock-based compensation
                      52                               52  
Cash dividends
                                  (1,496 )                 (1,496 )
Other
          31             1             2                   3  
 
Balance at December 31, 2010
    843,814       (474 )   $ 4,219     $ 3,702     $ (15 )   $ 8,366     $ (70 )   $ 707     $ 16,909  
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2010, 2009, and 2008
Southern Company and Subsidiary Companies 2010 Annual Report
                         
 
    2010     2009     2008  
    (in millions)          
Consolidated Net Income
  $ 2,040     $ 1,708     $ 1,807  
 
Other comprehensive income:
                       
Qualifying hedges:
                       
Changes in fair value, net of tax of $-, $(3), and $(19), respectively
    (1 )     (4 )     (30 )
Reclassification adjustment for amounts included in net income, net of tax of $9, $18, and $7, respectively
    15       28       11  
Marketable securities:
                       
Change in fair value, net of tax of $(2), $1, and $(4), respectively
    (3 )     4       (7 )
Pension and other postretirement benefit plans:
                       
Benefit plan net gain (loss),net of tax of $1, $(8), and $(32), respectively
    6       (12 )     (51 )
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $1, respectively
    1       1       2  
 
Total other comprehensive income (loss)
    18       17       (75 )
 
Dividends on preferred and preference stock of subsidiaries
    (65 )     (65 )     (65 )
 
Consolidated Comprehensive Income
  $ 1,993     $ 1,660     $ 1,667  
 
The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2010 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Southern Company (the Company) is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power) – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.
The financial statements reflect Southern Company’s investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment, but is not the primary beneficiary. All material intercompany transactions have been eliminated in consolidation. Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation.
The traditional operating companies, Southern Power, and certain of their subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC) and the traditional operating companies are also subject to regulation by their respective state public service commissions (PSC). The companies follow generally accepted accounting principles (GAAP) in the U.S. and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates.

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NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Regulatory Assets and Liabilities
The traditional operating companies are subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
                         
 
    2010     2009     Note  
    (in millions)          
Deferred income tax charges
  $ 1,204     $ 1,048       (a )
Deferred income tax charges — Medicare subsidy
    82             (k )
Asset retirement obligations-asset
    79       125       (a,i )
Asset retirement obligations-liability
    (82 )     (47 )     (a,i )
Other cost of removal obligations
    (1,188 )     (1,307 )     (a )
Deferred income tax credits
    (237 )     (249 )     (a )
Loss on reacquired debt
    274       255       (b )
Vacation pay
    151       145       (c,i )
Under recovered regulatory clause revenues
    27       40       (d )
Over recovered regulatory clause revenues
    (40 )     (218 )     (d )
Building leases
    45       47       (f )
Generating plant outage costs
    31       39       (d )
Under recovered storm damage costs
    8       22       (d )
Property damage reserves
    (216 )     (157 )     (h )
Fuel hedging-asset
    211       187       (d )
Fuel hedging-liability
    (7 )     (2 )     (d )
Other assets
    171       156       (d )
Environmental remediation-asset
    67       68       (h,i )
Environmental remediation-liability
    (10 )     (13 )     (h )
Environmental compliance cost recovery
          (96 )     (g )
Other liabilities
    (13 )     (51 )     (j )
Retiree benefit plans
    2,041       2,268       (e,i )
 
Total assets (liabilities), net
  $ 2,598     $ 2,260          
 
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)   Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and other cost of removal liabilities will be settled and trued up following completion of the related activities. Other cost of removal obligations include $92 million at Georgia Power that will be amortized over a three-year period beginning January 1, 2011 in accordance with a Georgia PSC order. See Note 3 under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” for additional information.
 
(b)   Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years.
 
(c)   Recorded as earned by employees and recovered as paid, generally within one year.
 
(d)   Recorded and recovered or amortized as approved by the appropriate state PSCs over periods not exceeding 10 years.
 
(e)   Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.
 
(f)   Recovered over the remaining lives of the buildings through 2026.
 
(g)   Deferred revenue associated with the levelization of Georgia Power’s environmental compliance cost recovery (ECCR) tariff revenue for the years 2008 through 2010 in accordance with a Georgia PSC order.
 
(h)   Recovered as storm restoration or environmental remediation expenses are incurred.
 
(i)   Not earning a return as offset in rate base by a corresponding asset or liability.
 
(j)   Recorded and recovered or amortized as approved by the appropriate state PSC over periods up to the life of the plant or the remaining life of the original issue or, if refinanced, over the life of the new issue which may range up to 50 years.
 
(k)   Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 14 years. See Note 5 under “Current and Deferred Income Taxes” for additional information.
In the event that a portion of a traditional operating company’s operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off or reclassify to accumulated other comprehensive income (OCI) related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional operating company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under “Retail Regulatory

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NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Matters — Alabama Power,” “Retail Regulatory Matters — Georgia Power,” and “Retail Regulatory Matters — Mississippi Power Integrated Coal Gasification Combined Cycle” for additional information.
Revenues
Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors.
Southern Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense generally includes the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under “Nuclear Fuel Disposal Costs” for additional information.
Income and Other Taxes
Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
In accordance with regulatory requirements, deferred investment tax credits (ITCs) for the traditional operating companies are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $23 million in 2010, $24 million in 2009, and $23 million in 2008. At December 31, 2010, all ITCs available to reduce federal income taxes payable had been utilized.
Under the American Recovery and Reinvestment Act of 2009, certain projects at certain Southern Company subsidiaries are eligible for ITCs or cash grants. These subsidiaries have elected to receive ITCs. The credits are recorded as a deferred credit, which will be amortized over the life of the asset, and the tax basis of the asset is reduced by 50% of the credits received, resulting in a deferred tax asset. The subsidiaries have elected to recognize the tax benefit of this basis difference as a reduction to income tax expense as costs are incurred during the construction period. These basis differences will reverse and be recorded to income tax expense over the useful life of the asset once placed in service.
In accordance with accounting standards related to the uncertainty in income taxes, Southern Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.

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NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Southern Company’s property, plant, and equipment consisted of the following at December 31:
                 
    2010     2009  
    (in millions)  
Generation
  $ 30,121     $ 28,204  
Transmission
    7,835       7,380  
Distribution
    14,870       14,335  
General
    3,116       2,917  
Plant acquisition adjustment
    43       43  
 
Utility plant in service
    55,985       52,879  
 
Information technology equipment and software
    216       182  
Communications equipment
    423       423  
Other
    107       104  
 
Other plant in service
    746       709  
 
Total plant in service
  $ 56,731     $ 53,588  
 
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific state PSC orders. Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit’s operating cycle. The refueling cycles for Alabama Power and Georgia Power range from 18 to 24 months for each unit. In accordance with a Georgia PSC order, Georgia Power also defers the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortizes such costs over 10 years, which approximates the expected maintenance cycle.
The amount of non-cash property additions recognized for the years ended December 31, 2010, 2009, and 2008 was $427 million, $370 million, and $309 million, respectively. These amounts are comprised of construction related accounts payable outstanding at each year end together with retention amounts accrued during the respective year.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.3% in 2010, 3.2% in 2009, and 3.2% in 2008. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC for the traditional operating companies. Accumulated depreciation for utility plant in service totaled $19.7 billion and $18.7 billion at December 31, 2010 and 2009, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
In August 2009, the Georgia PSC approved an accounting order allowing Georgia Power to amortize a portion of its regulatory liability related to other cost of removal obligations. See Note 3 under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” for additional information.
Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 30 years. Accumulated depreciation for other plant in service totaled $441 million and $419 million at December 31, 2010 and 2009, respectively.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. The Company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 3 under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” for additional information related to Georgia Power’s cost of removal regulatory liability.

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NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facilities, Plants Farley, Hatch, and Vogtle. In addition, the Company has retirement obligations related to various landfill sites, ash ponds, underground storage tanks, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See “Nuclear Decommissioning” herein for further information on amounts included in rates.
Details of the asset retirement obligations included in the balance sheets are as follows:
                 
    2010     2009  
    (in millions)  
Balance at beginning of year
  $ 1,206     $ 1,185  
Liabilities incurred
          2  
Liabilities settled
    (16 )     (10 )
Accretion
    78       77  
Cash flow revisions
    (2 )     (48 )
 
Balance at end of year
  $ 1,266     $ 1,206  
 
Nuclear Decommissioning
The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC’s regulations. Use of the Funds is restricted to nuclear decommissioning activities and the Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds’ managers to exercise the standard of care in investing that a “prudent investor” would use in the same circumstances. The FERC regulations also require, except for investments tied to market indices or other mutual funds, that the Funds’ managers may not invest in any securities of the utility for which it manages funds or its affiliates. In addition, the NRC prohibits investments in securities of power reactor licensees. While Southern Company is allowed to prescribe an overall investment policy to the Funds’ managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by Southern Company, Alabama Power, and Georgia Power management. The Funds’ managers are authorized, within broad limits, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds’ investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.
Southern Company records the investment securities held in the Funds at fair value, as disclosed in Note 10. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.
The Funds at Georgia Power participate in a securities lending program through the managers of the Funds. Under this program, the Funds’ investment securities are loaned to investment brokers for a fee. Securities so loaned are fully collateralized by cash, letters of credit, and securities issued or guaranteed by the U.S. government, its agencies, and the instrumentalities. As of December 31, 2010 and 2009, approximately $141 million and $14 million, respectively, of the fair market value of the Funds’ securities were on loan and pledged to creditors under the Funds’ managers’ securities lending program. The fair value of the collateral received was approximately $144 million and $14 million at December 31, 2010 and 2009, respectively, and can only be sold upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows.
At December 31, 2010, investment securities in the Funds totaled $1.4 billion consisting of equity securities of $664 million, debt securities of $632 million, and $74 million of other securities. At December 31, 2009, investment securities in the Funds totaled $1.1 billion consisting of equity securities of $774 million, debt securities of $272 million, and $22 million of other securities. These amounts include the investment securities pledged to creditors and collateral received, and exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases and the lending pool.

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NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Sales of the securities held in the Funds resulted in cash proceeds of $2.0 billion, $1.2 billion, and $712 million in 2010, 2009, and 2008, respectively, all of which were reinvested. For 2010, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $139 million, of which $6 million related to securities held in the Funds at December 31, 2010. For 2009, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $215 million, of which $198 million related to securities held in the Funds at December 31, 2009. For 2008, fair value reductions, including reinvested interest and dividends and excluding the Funds’ expenses, were $(278) million. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of and purpose for which the securities were acquired.
Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the Alabama PSC. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.
At December 31, 2010, the accumulated provisions for decommissioning were as follows:
                         
    Plant Farley     Plant Hatch     Plant Vogtle  
    (in millions)  
External trust funds
  $ 553     $ 360     $ 206  
Internal reserves
    24              
 
Total
  $ 577     $ 360     $ 206  
 
Site study cost is the estimate to decommission a specific facility as of the site study year. The estimated costs of decommissioning based on the most current studies, which were performed in 2008 for Alabama Power’s Plant Farley and in 2009 for the Georgia Power plants, were as follows for Alabama Power’s Plant Farley and Georgia Power’s ownership interests in Plants Hatch and Vogtle:
                         
    Plant Farley     Plant Hatch     Plant Vogtle  
Decommissioning periods:
                       
Beginning year
    2037       2034       2047  
Completion year
    2065       2063       2067  
 
    (in millions)
Site study costs:
                       
Radiated structures
  $ 1,060     $ 583     $ 500  
Non-radiated structures
    72       46       71  
 
Total
  $ 1,132     $ 629     $ 571  
 
The decommissioning periods and site study costs for Plant Vogtle reflect the extended operating license approved by the NRC in June 2009. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.
For ratemaking purposes, Alabama Power’s decommissioning costs are based on the site study, and Georgia Power’s decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2006. The estimates used in current rates are $575 million and $420 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Amounts expensed were $3 million annually for Plant Vogtle Units 1 and 2 for 2008 through 2010. Effective for the years 2011 through 2013, the annual decommissioning cost for ratemaking is $2 million for Plant Hatch. Georgia Power projects the external trust funds for Plant Vogtle Units 1 and 2 would be adequate to meet the decommissioning obligations of the NRC with no further contributions. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively. As a result of license extensions, amounts previously contributed to the external trust funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations.

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NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the traditional operating companies record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional operating companies’ regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 12.5%, 15.3%, and 11.2% of net income for 2010, 2009, and 2008, respectively.
Cash payments for interest totaled $789 million, $788 million, and $787 million in 2010, 2009, and 2008, respectively, net of amounts capitalized of $86 million, $84 million, and $71 million, respectively.
Impairment of Long-Lived Assets and Intangibles
Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Storm Damage Reserves
Each traditional operating company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional operating companies accrued $32 million in 2010 and $44 million in 2009. Alabama Power, Gulf Power, and Mississippi Power also have discretionary authority from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2010 and 2009, such additional accruals totaled $48 million and $40 million, respectively, all at Alabama Power. There were no material accruals for 2008. See Note 3 under “Retail Regulatory Matters — Alabama Power — Natural Disaster Reserve” for additional information regarding Alabama Power’s natural disaster reserve.
Leveraged Leases
Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. The Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows.
Southern Company’s net investment in domestic leveraged leases consists of the following at December 31:
                 
    2010     2009  
    (in millions)  
Net rentals receivable
  $ 475     $ 487  
Unearned income
    (207 )     (218 )
 
Investment in leveraged leases
    268       269  
Deferred taxes from leveraged leases
    (223 )     (211 )
 
Net investment in leveraged leases
  $ 45     $ 58  
 

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NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
A summary of the components of income from domestic leveraged leases was as follows:
                         
    2010     2009     2008  
    (in millions)  
Pretax leveraged lease income
  $ 4     $ 12     $ 14  
Income tax expense
    (3 )     (5 )     (6 )
 
Net leveraged lease income
  $ 1     $ 7     $ 8  
 
Southern Company’s net investment in international leveraged leases consists of the following at December 31:
                 
    2010     2009  
    (in millions)  
Net rentals receivable
  $ 733     $ 734  
Unearned income
    (377 )     (393 )
 
Investment in leveraged leases
    356       341  
Current taxes payable
           
Deferred taxes from leveraged leases
    (40 )     (40 )
 
Net investment in leveraged leases
  $ 316     $ 301  
 
A summary of the components of income from international leveraged leases was as follows:
                         
    2010     2009     2008  
    (in millions)  
Pretax leveraged lease income (loss)
  $ 14     $ 19     $ (99 )
Income tax benefit (expense)
    (5 )     (7 )     35  
 
Net leveraged lease income (loss)
  $ 9     $ 12     $ (64 )
 
The Company terminated two international leveraged lease investments during 2009. The proceeds were used to extinguish all debt related to leveraged lease investments, a portion of which had make-whole redemption provisions. This resulted in a $17 million loss which partially offset a $26 million gain on the terminations.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average costs of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the traditional operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.
Financial Instruments
Southern Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 10 for additional information. Substantially all of Southern Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the “normal” scope exception, and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional operating companies’ fuel hedging programs. This results in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any

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NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information.
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2010, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was not material.
Southern Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income.
Accumulated OCI (loss) balances, net of tax effects, were as follows:
                                 
                    Pension and Other   Accumulated Other
    Qualifying   Marketable   Postretirement   Comprehensive
    Hedges   Securities   Benefit Plans   Income (Loss)
    (in millions)
Balance at December 31, 2009
  $ (49 )   $ 10     $ (49 )   $ (88 )
Current period change
    14       (3 )     7       18  
 
Balance at December 31, 2010
  $ (35 )   $ 7     $ (42 )   $ (70 )
 
Variable Interest Entities
Effective January 1, 2010, the traditional operating companies and Southern Power adopted new accounting guidance which modified the consolidation model and expanded disclosures related to variable interest entities (VIE). The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The adoption of this new accounting guidance did not result in the traditional operating companies or Southern Power consolidating any VIEs that were not already consolidated under previous guidance, nor deconsolidating any VIEs.
Certain of the traditional operating companies have established certain wholly-owned trusts to issue preferred securities. See Note 6 under “Long-Term Debt Payable to Affiliated Trusts” for additional information. However, Southern Company and the applicable traditional operating companies are not considered the primary beneficiaries of the trusts. Therefore, the investments in these trusts are reflected as other investments, and the related loans from the trusts are reflected in long-term debt in the balance sheets.
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2010, the traditional operating companies and certain other subsidiaries contributed approximately $620 million to the qualified pension plan. No contributions to the qualified pension plan are expected for the year ending December 31, 2011. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2011, other postretirement trust contributions are expected to total approximately $31 million.

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NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2007 for the 2008 plan year using a discount rate of 6.30% and an annual salary increase of 3.75%.
                         
    2010     2009     2008  
 
Discount rate:
                       
Pension plans
    5.52 %     5.93 %     6.75 %
Other postretirement benefit plans
    5.40       5.83       6.75  
Annual salary increase
    3.84       4.18       3.75  
Long-term return on plan assets:
                       
Pension plans
    8.75       8.50       8.50  
Other postretirement benefit plans
    7.40       7.51       7.59  
 
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio.
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate of 8.25% for 2011, decreasing gradually to 5.0% through the year 2019 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2010 as follows:
                 
    1 Percent   1 Percent
    Increase   Decrease
    (in millions)  
Benefit obligation
  $ 128     $ 108  
Service and interest costs
    7       6  
 
Pension Plans
The total accumulated benefit obligation for the pension plans was $6.7 billion in 2010 and $6.3 billion in 2009. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2010 and 2009 were as follows:
                 
    2010     2009  
    (in millions)  
Change in benefit obligation
               
Benefit obligation at beginning of year
  $ 6,758     $ 5,879  
Service cost
    172       146  
Interest cost
    391       387  
Benefits paid
    (296 )     (282 )
Actuarial loss (gain)
    198       628  
 
Balance at end of year
    7,223       6,758  
 
Change in plan assets
               
Fair value of plan assets at beginning of year
    5,627       5,093  
Actual return (loss) on plan assets
    859       792  
Employer contributions
    644       24  
Benefits paid
    (296 )     (282 )
 
Fair value of plan assets at end of year
    6,834       5,627  
 
Accrued liability
  $ (389 )   $ (1,131 )
 
At December 31, 2010, the projected benefit obligations for the qualified and non-qualified pension plans were $6.7 billion and $0.5 billion, respectively. All pension plan assets are related to the qualified pension plan.

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NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Company’s pension plans consist of the following:
                 
    2010     2009  
    (in millions)  
Prepaid pension costs
  $ 88     $  
Other regulatory assets, deferred
    1,749       1,894  
Other current liabilities
    (28 )     (25 )
Employee benefit obligations
    (449 )     (1,106 )
Accumulated OCI
    68       74  
 
Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2010 and 2009 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2011.
                 
    Prior Service Cost   Net (Gain) Loss
    (in millions)
Balance at December 31, 2010:
               
Accumulated OCI
  $ 8     $ 60  
Regulatory assets
    159       1,590  
 
Total
  $ 167     $ 1,650  
 
 
               
Balance at December 31, 2009:
               
Accumulated OCI
  $ 10     $ 64  
Regulatory assets
    188       1,706  
 
Total
  $ 198     $ 1,770  
 
 
               
Estimated amortization in net periodic pension cost in 2011:
               
Accumulated OCI
  $ 1     $ 1  
Regulatory assets
    31       20  
 
Total
  $ 32     $ 21  
 
The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2010 and 2009 are presented in the following table:
                 
    Accumulated   Regulatory
    OCI   Assets
    (in millions)
Balance at December 31, 2008
  $ 54     $ 1,579  
Net loss
    21       355  
Change in prior service costs
          1  
Reclassification adjustments:
               
Amortization of prior service costs
    (1 )     (34 )
Amortization of net gain
          (7 )
 
Total reclassification adjustments
    (1 )     (41 )
 
Total change
    20       315  
 
Balance at December 31, 2009
    74       1,894  
Net gain
    (4 )     (106 )
Change in prior service costs
          2  
Reclassification adjustments:
               
Amortization of prior service costs
    (1 )     (32 )
Amortization of net gain
    (1 )     (9 )
 
Total reclassification adjustments
    (2 )     (41 )
 
Total change
    (6 )     (145 )
 
Balance at December 31, 2010
  $ 68     $ 1,749  
 

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NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Components of net periodic pension cost were as follows:
                         
    2010     2009     2008  
    (in millions)  
Service cost
  $ 172     $ 146     $ 146  
Interest cost
    391       387       348  
Expected return on plan assets
    (552 )     (541 )     (525 )
Recognized net loss
    10       7       9  
Net amortization
    33       35       37  
 
Net periodic pension cost
  $ 54     $ 34     $ 15  
 
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2010, estimated benefit payments were as follows:
         
    Benefit Payments
    (in millions)
2011
  $ 335  
2012
    353  
2013
    372 &n